ENBRIDGE INCOME PARTNERS LP

MANAGEMENT’S DISCUSSION AND ANALYSIS

December 31, 2015

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MANAGEMENT’S DISCUSSION AND ANALYSIS This Management’s Discussion and Analysis (MD&A) dated February 19, 2016 should be read in conjunction with the audited consolidated financial statements and notes thereto of Enbridge Income Partners LP (EIPLP) for the year ended December 31, 2015, prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). All financial measures presented in this MD&A are expressed in Canadian dollars, unless otherwise indicated. Additional information related to EIPLP is available under Enbridge Income Fund’s (the Fund) profile on SEDAR at www.sedar.com. OVERVIEW EIPLP is involved in the generation, transportation and storage of energy through its interests in its liquids pipelines business, including the Canadian Mainline, its 50% interest in the Canadian and United States portions of Alliance Pipeline, which transports natural gas, and its renewable and alternative power generation assets. EIPLP was formed in 2002. THE 2015 TRANSACTION On September 1, 2015, EIPLP acquired 100% interests in the following entities (collectively, the Purchased Entities) from Enbridge Inc. (Enbridge) and certain of its subsidiaries for an aggregate consideration of $30.4 billion plus incentive distribution and performance rights, less working capital adjustments (the 2015 Transaction):

• Enbridge Pipelines Inc. (EPI) • Enbridge Pipelines (Athabasca) Inc. (EPAI) • Enbridge Hardisty Storage Inc. • Enbridge Southern Lights GP Inc. • Enbridge Lac Alfred Wind Project GP Inc. • Enbridge Massif du Sud Wind Project GP Inc. • Enbridge Blackspring Ridge I Wind Project GP Inc. • Enbridge Saint Robert Bellarmin Wind Project GP Inc.

Prior to September 1, 2015, EIPLP, the entity that directly holds the underlying operating assets and liabilities, was 100% owned and controlled by Enbridge Commercial Trust (ECT) and by the general partner, a subsidiary of ECT, through their holdings in Class A units of EIPLP. Both entities at the time were wholly-owned consolidated subsidiaries of the Fund. The unitholders of the Fund are Enbridge Income Fund Holdings Inc. (ENF), a public company listed on the Toronto Stock Exchange (TSX), and Enbridge, a North American transporter, distributor and generator of energy listed on the TSX and New York Stock Exchange. The general partner has the right to manage, control and operate the businesses of EIPLP. The Fund, ECT, EIPLP and its subsidiaries are referred to as the Fund Group. Enbridge Management Services Inc. (EMSI or the Manager), a wholly-owned subsidiary of Enbridge, administers the Fund Group and as part of the 2015 Transaction is responsible for the operations and day-to-day management of the Purchased Entities as well as the assets previously held by EIPLP. The Manager also provides EIPLP administrative and general support services. Upon closing of the 2015 Transaction, Enbridge acquired a controlling interest in EIPLP of approximately 57% reducing ECT’s ownership to approximately 43%. Additionally, Enbridge now holds a 51% direct interest in the general partner of EIPLP. Consequently, ECT ceased to consolidate EIPLP. The ECT trust indenture was amended to provide for appointment of trustees by Enbridge in accordance with its economic interest in ENF and the Fund Group. As a result, the Fund ceased to consolidate ECT as it is no longer the primary beneficiary of ECT nor does it control ECT. The Fund continues to participate in the ownership and management of the indirectly owned entities held by EIPLP through its governance structure, which includes Trustee oversight and decision making related to the underlying assets.

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As a result of the 2015 Transaction, EIPLP allocates earnings based on the Hypothetical Liquidation at Book Value (HLBV) method. The HLBV method is applied for allocation of earnings and other comprehensive income (OCI) where cash distributions, including both preference and residual distributions, are not based on the investor’s ownership percentages. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that partners would receive if EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, are the partners’ share of the earnings or loss from EIPLP for the period. The 2015 Transaction was accounted for as a transaction among entities under common control, similar to a pooling of interests, whereby the assets and liabilities acquired were recorded at Enbridge’s historic carrying values. Financial information for periods prior to September 1, 2015 have been retrospectively adjusted to present the result of operations for EIPLP and its interests in the Purchased Entities on a combined basis. THE 2014 TRANSACTION On November 7, 2014, EIPLP completed a transaction whereby it acquired from Enbridge a 50% equity interest in the United States portion of Alliance Pipeline (Alliance Pipeline US) and subscribed for and purchased Class A Units of certain Enbridge subsidiaries which provide a defined cash flow stream from the Southern Lights Pipeline (Southern Lights Class A Units) for aggregate consideration of $1.8 billion (the 2014 Transaction). At the time of the 2014 Transaction, EIPLP previously owned a 50% investment in the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada). The Alliance Pipeline US component of the 2014 Transaction was accounted for as a transaction among entities under common control, similar to the 2015 Transaction. Financial information for periods prior to November 7, 2014 have been retrospectively adjusted to present the result of operations for EIPLP and its interests in Alliance Pipeline US on a combined basis. The Southern Lights Class A Unit component of the 2014 Transaction was accounted for as a loan investment and did not require retrospective restatement. As part of the 2015 Transaction, EIPLP indirectly acquired the Class B Units of the Canadian portion of Southern Lights Pipeline (Southern Lights Canada). Together, with the Class A Units EIPLP acquired in the 2014 Transaction, EIPLP holds all the ownership, economic interests and voting rights, direct and indirect, in Southern Lights Canada. For further details refer to Liquids Pipelines – Southern Lights Pipeline. OPERATING SEGMENTS EIPLP conducts its business through three business segments: Liquids Pipelines, Gas Pipelines and Green Power. These operating segments are strategic business units established by senior management to facilitate the achievement of EIPLP’s long-term objectives and the objectives of EIPLP’s partners, as well as to aid in resource allocation decisions and to assess operational performance. Financing costs, current and deferred income taxes and other costs not attributable to specific business segments are presented on a consolidated basis. Liquids Pipelines Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGL) and refined products pipelines, feeder pipelines, gathering systems and terminals in Canada, including Canadian Mainline, Regional Oil Sands System, Southern Lights Pipeline, which includes Southern Lights Canada and Class A Units of the United States portion of Southern Lights (Southern Lights US), and Feeder Pipelines and Other. Gas Pipelines Gas Pipelines includes EIPLP’s 50% interest in both the Canadian and United States portions of the Alliance Pipeline system, which transports liquids-rich natural gas from northeast British Columbia, northwest Alberta and the Bakken area of North Dakota to Channahon, Illinois.

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Green Power Green Power includes approximately 1,437 megawatts (MW) (1,052 MW net after taking into account third party interests) of renewable and alternative energy generating capacity from wind farms located in Alberta, Saskatchewan, Ontario and Quebec and solar facilities located in Ontario. PERFORMANCE OVERVIEW

Three months ended Year ended December 31, December 31, 2015 2014 2015 2014 2013

(millions of Canadian dollars) Earnings attributable to partners1 Liquids Pipelines 286 (4) (1) 575 647 Gas Pipelines 36 28 144 132 117 Green Power 45 38 154 127 33 Eliminations and Other 20 23 151 108 83 Earnings before interest and income taxes 387 85 448 942 880 Interest expense (95) (75) (327) (316) (301) Income taxes recovery/(expense) (20) 35 59 5 (84) Special interest rights distributions - TPDR2 (44) - (58) - -

Earnings attributable to general and limited

partners 228 45 122 631 495 Adjusted earnings3 Liquids Pipelines 384 16 640 81 73 Gas Pipelines 37 26 151 74 57 Green Power 39 20 112 93 93 Eliminations and Other 18 - 30 - -

Adjusted earnings before interest and income

taxes 478 62 933 248 223 Interest expense (95) (12) (132) (12) (10) Income taxes (20) (9) (59) (38) (24) Adjusting items related to income taxes: Tax on adjusting items (21) (1) (70) 4 (6) Derecognition of regulatory balances - - 16 - - Impact of tax rate changes - - 18 - - Special interest rights distributions - TPDR2 (44) - (58) - -

Adjusted earnings attributable to general and

limited partners 298 40 648 202 183 Cash flow data1 Cash provided by operating activities 650 323 1,949 1,700 911 Cash used in investing activities (699) (3,096) (5,305) (3,472) (6,135) Cash provided by financing activities 104 2,803 3,321 1,800 5,107 Available cash flow from operations4 509 92 986 367 342 Distributions5 Cash distributions to ECT 169 107 546 349 305 Cash distributions to Enbridge 209 - 279 - - TPDR and Class D unit distributions to Enbridge2 45 - 59 - - Total revenues1 747 408 1,874 2,186 2,220 Total assets1 25,650 23,296 25,650 23,296 20,832 Total long-term liabilities1 14,959 6,280 14,959 6,280 7,989 1 Earnings, cash flow data, total revenues, total assets and total long-term liabilities have been retrospectively adjusted to reflect

the 2015 Transaction and the 2014 Transaction in information prior to the respective effective dates of the transactions as prescribed by U.S. GAAP for common control transactions.

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2 Temporary Performance Distribution Right (TPDR) distributes Class D units and refers to the paid-in-kind component of the Special Interest Rights (SIR) distribution (see Canadian Restructuring Plan). Class D unit distributions are also paid-in-kind with the issuance of additional Class D units.

3 Adjusted earnings before interest and income taxes (adjusted EBIT) and adjusted earnings are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures, refer to page 8.

4 Available cash flow from operations (ACFFO) is defined as adjusted EBIT further adjusted for depreciation and amortization and distributions from investments in excess of/(less than) earnings, less deductions for maintenance capital expenditures, interest expense, applicable taxes and other adjusting items. For further information on ACFFO, refer to Performance Overview – Available Cash Flow from Operations. ACFFO is a non-GAAP measure that does not have any standardized meaning prescribed by U.S. GAAP – see Non-GAAP Measures.

5 Refer to Liquidity and Capital Resources – Sources and Uses of Cash – Distributions for distributions rates. CONSOLIDATED EARNINGS Earnings before interest and income taxes (EBIT) was $448 million for the year ended December 31, 2015 compared with $942 million and $880 million for the comparative 2014 and 2013 periods, respectively. Earnings attributable to the general and limited partners of EIPLP for the year ended December 31, 2015 was $122 million compared with earnings of $631 million for the year ended December 31, 2014 and earnings of $495 million for the year ended December 31, 2013. Despite the benefits of the 2015 Transaction and the 2014 Transaction, the comparability of EIPLP’s results was impacted by a number of unusual, non-recurring or non-operating factors, the most significant of which are changes in unrealized derivative fair value gains and losses. EIPLP has a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks. The changes in unrealized mark-to-market accounting impacts from this program create volatility in short-term earnings, but EIPLP believes over the long-term it supports reliable cash flows. The majority of EIPLP’s unrealized derivative fair value gains and losses are within its Liquids Pipelines segment, specifically within the Canadian Mainline, which was acquired in the 2015 Transaction. The changes in unrealized fair value losses on derivative financial instruments in the Canadian Mainline are used to risk manage exposures inherent within the Competitive Toll Settlement (CTS), namely foreign exchange, power cost variability and allowance oil commodity prices. For the years ended December 31, 2015, 2014 and 2013, Canadian Mainline recognized net unrealized derivative losses of $1,391 million, $499 million and $362 million, respectively. Excluding the impact of the changes in unrealized losses on derivative instruments, EIPLP earnings increased period-over-period primarily as a result of stronger operating performance from Canadian Mainline. Earnings from Canadian Mainline reflected positive effects of higher throughput, partly attributed to the expansion of the Canadian Mainline completed in July 2015, and through continued efforts to optimize capacity utilization and to enhance scheduling efficiency with shippers. Although throughput increased relative to the comparative periods in 2014, further throughput growth in 2015 was hindered by upstream plant maintenance in Alberta during the second and third quarters which impacted light volumes and an unplanned shutdown of a Midwest refinery that impacted the takeaway of heavy volumes in the third quarter. Other factors contributing to an increase in adjusted earnings were higher terminalling revenues and a favourable United States/Canada foreign exchange rate. Partially offsetting these positive factors was a lower average Canadian Mainline International Joint Tariff (IJT) Residual Benchmark Toll, although this impact lessened commencing the second quarter of 2015 as, effective April 1, 2015, this toll increased by US$0.10 per barrel to US$1.63 per barrel. Other factors negatively impacting earnings were higher power costs associated with higher throughput and higher depreciation expense due to an increased asset base. Partially mitigating the impact of a lower Canadian Mainline IJT Residual Benchmark Toll were new surcharges related to system expansions, including a surcharge for the Edmonton to Hardisty Expansion pipeline completed in April 2015. Within Gas Pipelines, earnings from Alliance Pipeline US for the year ended December 31, 2015 were higher compared with the corresponding 2014 and 2013 periods primarily due to the effects of favourable foreign exchange rates with respect to the unhedged portion of Alliance Pipeline US United States dollar cash flow, partially offset by the temporary service interruption on Alliance Pipeline Canada in August 2015.

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Higher earnings from Green Power for the year ended December 31, 2015 compared with the corresponding 2014 period reflected incremental earnings from the purchase of additional interests in the Lac Alfred and Massif du Sud wind projects in the fourth quarter of 2014. The significant increase in 2014 annual earnings when compared with 2013 was due to an unrealized fair value loss on the long-term power price derivative contracts acquired to hedge expected revenues and cash flows from Blackspring Ridge Wind Project being recognized in 2013. Finally, the change in Earnings attributable to general and limited partners period-over-period was also impacted by TPDR distributions on SIR issued as part of the 2015 Transaction, higher income tax recovery due to taxable losses and higher interest expense resulting from higher levels of debt in the third and fourth quarters of 2015. Fourth quarter performance drivers were largely consistent with year-to-date trends and continued to be impacted by changes in unrealized fair value derivative and foreign exchange gains and losses. Aside from the operating factors discussed in Adjusted Earnings, factors unique to the fourth quarter of 2015 included the impact of employee severance cost allocations in relation to Enbridge’s enterprise-wide reduction of workforce, which resulted in an $18 million charge included within Eliminations and Other. ADJUSTED EARNINGS Adjusted EBIT was $933 million for the year ended December 31, 2015 compared with $248 million and $223 million for the comparative 2014 and 2013 periods, respectively. The increase in adjusted EBIT is directly attributable to the significant increase of EIPLP’s asset base following the 2015 Transaction and the 2014 Transaction. The most notable assets contributing incremental adjusted EBIT were Canadian Mainline and Regional Oil Sands. Adjusted earnings attributable to general and limited partners, referred to as adjusted earnings, was $648 million for the year ended December 31, 2015 compared with $202 million and $183 million for the comparative 2014 and 2013 periods, respectively. The increases reflected in the adjusted EBIT discussion above were partially offset by higher interest expense due to higher levels of debt and higher income taxes expense due to increased business activity, as well as TPDR distributions on the SIR. The increase in adjusted earnings in the fourth quarter of 2015, compared with the same period of 2014, is a direct reflection of the contributions from the 2015 Transaction. AVAILABLE CASH FLOW FROM OPERATIONS

ACFFO represents cash available to fund distributions on Class A and Class C units, as well as for debt repayments and reserves. Such reserves are determined by the Manager and are used for payment of committed charges, such as interest and income taxes, and for execution of the capital maintenance program. For the year ended December 31, 2015, EIPLP’s ACFFO was $986 million compared with $367 million and $342 million for the comparative 2014 and 2013 periods, respectively. Similar to adjusted EBIT, the increase in ACFFO is driven by the significant increase of EIPLP’s asset base following the 2015 Transaction and the 2014 Transaction. The period-over-period increase was partially offset by higher maintenance capital expenditures, higher interest expense due to higher outstanding debt balances and higher income taxes expense in 2015 resulting from increased business activity associated with the increased asset base. ACFFO increased for the three months ended December 31, 2015 compared with the three months ended December 31, 2014 and largely reflected similar trends as noted above for the year-to-date results. CASH FLOWS Cash provided by operating activities was $1,949 million for the year ended December 31, 2015 compared with $1,700 million and $911 million for the years ended December 31, 2014 and 2013, respectively. The year over year increases were mainly driven by strong operating performance from

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EIPLP’s core assets, particularly from Liquids Pipelines, and the cash flow generated from growth projects placed into service in recent years. To finance the 2015 Transaction, in addition to issuing equity to Enbridge as a portion of the consideration for the Purchased Entities acquired from Enbridge and certain of its subsidiaries, Class A units were issued to ECT for $3,000 million to provide the cash component. Additional Class A units were issued to ECT in November 2015 subsequent to ENF’s public issuance to facilitate the funding of the secured capital growth program. As part of the 2014 Transaction, EIPLP made a significant investment in Alliance Pipeline US and subscribed for and purchased Southern Lights Class A Units which provide a defined cash flow stream from the Southern Lights Pipeline. To finance these investments, EIPLP issued Class A units to ECT for $1,760 million. In 2013, a subsidiary of EIPLP invested $2,690 million in preference shares of an affiliated company, which were subsequently redeemed for the same amount by that affiliated company in 2014 resulting in a cash inflow for EIPLP. In addition to the above transactions, EIPLP’s cash flows fluctuate with normal business activities. The financing and investing activities cash flows are impacted by the financing and constructing of the secured capital growth program in years prior to those projects going into service and providing cash inflows for operating activities. DISTRIBUTIONS Distributions to partners are declared monthly and paid in the following month. Cash distributions to ECT based on Class A unit ownership were declared at an annual aggregate rate of $1.9669 per unit representing $546 million for the year ended December 31, 2015 compared with $1.7621 per unit or $349 million for the year ended December 31, 2014 and $1.6251 per unit or $305 million for the year ended December 31, 2013. Cash distributions to Enbridge based on Class C unit ownership were declared at an annual aggregate rate of $0.6297 per unit or $279 million for the year ended December 31, 2015. Paid-in-kind distributions to Enbridge on Class D unit ownership were $1 million and the TPDR component of the SIR were $58 million for the year ended December 31, 2015. Refer to Liquidity and Capital Resources – Sources and Uses of Cash – Distributions for more details on the distributions. The year over year increase in the distributions declared is a direct result of the units issued during the year. A portion of the Class A units issued, as well as the Class C units and SIR were issued in conjunction with the 2015 Transaction (refer to Canadian Restructuring Plan). Additionally, the Class A units’ distribution rates for 2015 were higher than in prior years. REVENUES EIPLP generates revenues from three primary sources: transportation and other services, electricity sales and revenues from affiliates. Transportation and other services revenue of $1,501 million for the year ended December 31, 2015 (2014 - $1,877 million; 2013 - $1,916 million) were earned from EIPLP’s crude oil transportation businesses. For EIPLP’s transportation assets operating under market-based arrangements, revenues are driven by volumes transported and tolls. For assets operating under take-or-pay contracts, revenues reflect the terms of the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator, and in most cost-of-service based arrangements are reflective of EIPLP’s cost to provide the service plus a regulator-approved rate of return. Increased throughput on EIPLP’s core liquids pipeline assets combined with incremental revenues associated with assets placed into service over the past two years resulted in revenue increases; however, these increases were more than offset by unrealized derivative fair value losses on foreign exchange contracts. Electricity sales of $295 million for the year ended December 31, 2015 (2014 - $258 million; 2013 - $233 million) include power production revenues from EIPLP’s portfolio of renewable and power generation

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assets. Higher revenues reflected incremental revenues from the purchase of additional interests in the Lac Alfred and Massif du Sud wind projects in the fourth quarter of 2014. EIPLP’s revenues also included changes in unrealized derivative fair value gains and losses related to foreign exchange and commodity price contracts used to manage exposures from movements in foreign exchange rates and commodity prices. The unrealized mark-to-market accounting creates volatility and impacts the comparability of revenues in the short-term, but EIPLP believes over the long-term, the economic hedging program supports reliable cash flows. FORWARD-LOOKING INFORMATION Forward-looking information, or forward-looking statements, have been included in this MD&A to provide information about EIPLP and EIPLP’s subsidiaries and affiliates, including management’s assessment of EIPLP’s future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as “anticipate”, “expect”, “project”, “estimate”, “forecast”, “plan”, “intend”, “target”, “believe”, “likely” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected earnings/(loss) before interest and income taxes or adjusted earnings/(loss) before interest and income taxes; expected earnings/(loss)or adjusted earnings/(loss); expected future ACFFO; expected future cash flows; expected future distributions and policy; expected costs related to projects under construction; expected in-service dates for projects under construction; expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the 2015 Transaction; and expected capital expenditures. Although EIPLP believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, NGL and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; expected exchange rates; inflation; interest rates; completion of growth projects; availability and price of labour and pipeline construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for EIPLP’s projects; anticipated in-service dates; weather; the impact of the 2015 Transaction and distribution policy on cash flows; expected future ACFFO; and capital project funding. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for EIPLP’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which EIPLP operates and may impact levels of demand for EIPLP’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected EBIT, adjusted EBIT, expected earnings/(loss), adjusted earnings/(loss), ACFFO, the impact of the 2015 Transaction or estimated future distributions. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and pipeline construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer and regulatory approvals on construction and in-service schedules. EIPLP’s forward-looking statements are subject to risks and uncertainties pertaining to the impact of the 2015 Transaction, distribution policy, operating performance, regulatory parameters, project approval and support, weather, economic and competitive conditions, public opinion, changes in tax law and tax rate increases, exchange rates, interest rates, commodity prices and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this MD&A. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and EIPLP’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, EIPLP assumes no obligation to publicly update or revise any forward-looking statements made in this MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to EIPLP or persons acting on EIPLP’s behalf, are expressly qualified in their entirety by these cautionary statements.

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NON-GAAP MEASURES This MD&A contains references to adjusted EBIT, adjusted earnings and ACFFO. Adjusted EBIT represents EBIT adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. Adjusted earnings represents earnings adjusted for unusual, non-recurring or non-operating factors included in adjusted EBIT, as well as adjustments for unusual, non-recurring or non-operating factors in respect of interest expense and income taxes on a consolidated basis. These factors, referred to as adjusting items, are reconciled and discussed in the financial results sections for the affected business segments. Adjusting items referred to as changes in unrealized derivative fair value gains and losses are presented net of amounts realized on the settlement of derivative contracts during the applicable period. ACFFO represents EIPLP’s cash available to fund distributions to partners as well as for debt repayments and reserves. ACFFO consists of adjusted EBIT further adjusted for non-cash items, representing cash flow from EIPLP’s underlying businesses, less deductions for maintenance capital expenditures, interest expense, applicable taxes and other reserves pertaining to items of an unusual or transient nature which are not indicative of the underlying or sustainable cash flows of the business. ACFFO is important to unitholders as the Fund Group’s objective is to provide a predictable flow of distributions to unitholders. The Manager believes the presentation of adjusted EBIT, adjusted earnings and ACFFO provides useful information to investors and unitholders and provides increased transparency and insight into the performance of EIPLP. The Manager uses adjusted EBIT and adjusted earnings to set targets and to assess the performance of EIPLP. The Manager also uses ACFFO to assess the performance of EIPLP. Adjusted EBIT, adjusted earnings and ACFFO are not measures that have standardized meanings prescribed by U.S. GAAP and are not considered U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. Please refer to the EBIT reconciliations within the financial results for each business segment, the ACFFO reconciliation in Performance Overview – Available Cash Flow from Operations and the reconciliation between GAAP and adjusted earnings below.

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NON-GAAP RECONCILIATIONS EBIT to Adjusted EBIT

Three months ended Year ended December 31, December 31, 2015 2014 2015 2014 2013

(millions of Canadian dollars) Earnings before interest and income taxes 387 85 448 942 880 Retrospective adjustments1: 2015 Transaction - Liquids Pipelines - 11 324 (491) (596) 2015 Transaction - Green Power - (18) (36) (37) 60 2015 Transaction - Eliminations and Other - (7) (9) (92) (83) 2014 Transaction - Gas Pipelines - (8) - (64) (62) Adjusting items2: Changes in unrealized derivative fair value loss 116 39 371 25 -

Translation of foreign intercompany loan,

unrealized (20) (16) (130) (16) - Gain on sale of certain Virden System assets - - (22) - - Leak insurance recoveries (22) - (22) - - Employee severance cost allocation 18 - 18 - - Derecognition of regulatory balances - - (8) - 17 Realized gain on subscription price - (22) - (22) - Other (1) (2) (1) 3 7 Adjusted earnings before interest and income tax 478 62 933 248 223 1 The impact of the retrospective adjustments related to the 2015 Transaction and 2014 Transaction has been removed from

adjusted EBIT to reflect earnings generated under EIPLP’s ownership effective September 1, 2015 and November 7, 2014, respectively. Retrospective adjustments also include the impacts of significant, unusual, non-recurring or non-operating factors included in the retrospectively adjusted amounts for U.S. GAAP purposes.

2 The above table summarizes adjusting items by nature. For a detailed listing of adjusting items by segment, refer to individual segment discussions.

Available Cash Flow from Operations

Three months ended Year ended December 31, December 31, 2015 2014 2015 2014 2013

(millions of Canadian dollars) Adjusted EBIT 478 62 933 248 223 Depreciation and amortization expense 155 35 299 135 130 Distributions from Southern Lights Class A Units 4 2 20 2 - Cash distributions in excess of equity earnings 3 1 (12) 11 14 Maintenance capital expenditures1 (6) (7) (40) (13) (12) Interest expense (91) (3) (124) (12) (12) Adjusted current income tax recovery/(expense)2 (41) 2 (97) (4) (1) Other adjusting items 7 - 7 - - Available cash flow from operations (ACFFO) 509 92 986 367 342 1 Maintenance capital expenditures are expenditures that are required for the ongoing support and maintenance of the existing

pipeline system or that are necessary to maintain the service capability of the existing assets (including the replacement of components that are worn, obsolete, or completing their useful lives). For the purpose of ACFFO, maintenance capital excludes expenditures that extend asset useful lives, increase capacities from existing levels or reduce costs to enhance revenues or provide enhancements to the service capability of the existing assets.

2 Includes current income tax expense adjusted for tax on items of an unusual or transient nature which are not indicative of the underlying business or sustainable cash flows of the business.

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CANADIAN RESTRUCTURING PLAN On September 1, 2015, EIPLP completed the Canadian Restructuring Plan, referred to as the 2015 Transaction, for $30.4 billion plus incentive distribution and performance rights, less working capital adjustments. The Liquids Pipelines assets primarily consist of the Canadian Mainline, held through EPI, and the Regional Oil Sands System, held through EPAI. The Canadian Mainline includes a number of large diameter crude oil, NGL and refined products pipelines receiving hydrocarbon liquids at, and making deliveries to, various locations in western Canada and connecting to the Lakehead System, which is owned by Enbridge Energy Partners, L.P. (EEP), an affiliate of EIPLP, at the Canada/United States border near Gretna, Manitoba and Neche, North Dakota. The Canadian Mainline also includes a number of pipelines in eastern Canada. The Regional Oil Sands System includes a number of trunk line and lateral pipelines which collect synthetic crude oil and diluted bitumen from eight different producing oil sands projects for delivery to pipeline hub terminal locations at Edmonton, Alberta and Hardisty, Alberta. The Renewable Energy Assets include interests in three operational wind farms in Quebec and one operational wind farm in Alberta. CONSIDERATION EIPLP acquired all of the issued and outstanding shares of each of the Purchased Entities from Enbridge and certain of its subsidiaries. The aggregate purchase price payable by EIPLP to Enbridge consisted of approximately $2.7 billion in cash and $15.7 billion of units of EIPLP. EIPLP also assumed debt from the Purchased Entities with a book value of approximately $11.7 billion. To partially fund the 2015 Transaction, EIPLP issued 443 million Class C units at a price of $35.44 per unit. The EIPLP Class C units have direct voting rights and are entitled to non-cumulative distributions equivalent to distributions declared on an ordinary trust unit of the Fund (Fund Unit). The holders of Class C units have an exchange right which allows for an exchange of the EIPLP Class C units for Fund Units, ECT Preferred Units or common shares of ENF on a one-for-one basis at any time. In addition, a portion of the consideration included SIR issued to Enbridge. The holders of the SIR are entitled to receive Incentive Distribution Rights (IDR) and TPDR distributions (collectively, SIR distributions) in priority to any distributions which are to be paid to holders of any other units, except the EIPLP Class E unit, which are discussed below. The IDR includes a base annual incentive fee amount of $7.9 million and is also entitled to 25% of the pre-incentive distributable cash flow above a base distribution threshold of $1.295 per unit, reduced by a tax factor (unchanged from the pre-existing incentive sharing formula) which is paid out of ECT. Distributions over $1.890 per unit are distributed from EIPLP. The TPDR provides a distribution equivalent to 33% of pre-incentive distributable cash flow above the base distribution of $1.295 per unit. The TPDR is paid in the form of Class D units of EIPLP and will be issued each month until the later of the end of 2020 or 12 months after the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program) enters service. The Class D unitholders receive a distribution each month equal to the per unit amount paid on Class C units, but to be paid in kind in additional Class D units. Each Class D unit is convertible into a cash paying Class C unit of EIPLP in the fourth year after its issuance. The SIR have no direct voting rights, except in limited circumstances. The SIR are designed to provide consideration for the secured growth embedded within the transferred businesses; however, the cash outflows related to this incentive mechanism will be deferred (until such time as the units are convertible into a class of cash paying units in the fourth year after issuance). EIPLP also issued one Class E unit at a value of approximately $475 million to Enbridge. The EIPLP Class E unit is entitled to a redemption amount approximately equal to the Enbridge Employee Services Canada Inc. (EESCI) Series A Preferred Shares after-tax redemption amount. For further details on the EESCI Series A Preferred Shares refer to Related Party Transactions. The redemption amount will be paid in priority to all other distributions payable. This class of unit has no voting rights, except in limited circumstances.

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As a part of the 2015 Transaction, the general partner entered an agreement with EMSI to delegate the execution of certain of its powers to the Manager under an Intercorporate Services Agreement. The Manager will be responsible for the operations and day-to-day management of the Purchased Entities as well as assets previously held by EIPLP. The Manager will also provide administrative and general support services. OBJECTIVES AND STRATEGY EIPLP’s objective is to provide a predictable flow of distributable cash and to increase, where prudent, cash distributions to its partners, being ECT and Enbridge. EIPLP’s objectives and strategies are also aligned to support the corporate vision and strategies of ENF and the Fund, as well as of EIPLP’s sponsor, Enbridge. In order to achieve these objectives, the Manager pursues the following principal strategies which entail:

• Commitment to Safety and Operational Reliability; • Strengthen Core Businesses; • Focus on Project Management; and • Preserve Financing Strength and Flexibility.

COMMITMENT TO SAFETY AND OPERATIONAL RELIABILITY The commitment to safety and operational reliability means achieving and maintaining industry leadership in safety (process, public and personal) and ensuring the reliability and integrity of the systems Enbridge and its subsidiaries operate in order to generate, transport and deliver the energy society counts on and to protect the environment. Under the umbrella of Enbridge’s Operational Risk Management Plan (ORM Plan) introduced in 2010, Enbridge has undertaken extensive maintenance, integrity and inspection programs across its pipeline systems. The ORM Plan has resulted in strong improvements in the area of safety and operational risk management, bolstering incident response capabilities, employee and public safety protocols and improved communications with landowners and first responders. In addition, an enterprise-wide safety and risk management framework has been implemented to ensure Enbridge identifies, prioritizes and effectively prevents and mitigates risks across the enterprise. Enbridge strives to embed a common risk management framework within its operations and those of its joint venture partners. Supporting these initiatives is a safety culture that strives towards a target of 100% safe operations, with a belief that all incidents can be prevented. To achieve the goal of industry leadership, Enbridge measures its performance as compared to standard industry performance, transparently reports its results and continues to use external assessments to measure its performance. STRENGTHEN CORE BUSINESSES The 2015 Transaction was transformational for EIPLP. It provided a greater asset scale and is therefore, expected to enhance distributions to EIPLP’s partners. Within EIPLP’s liquids pipelines business, strategies to strengthen the core business are focused on optimizing asset performance, strengthening stakeholder and customer relationships and providing access to new markets for production from northwestern Canada, all while ensuring safe and reliable operations. EIPLP’s assets are strategically located and well-positioned to capitalize on opportunities. Throughout 2015, the Canadian Mainline has continued to optimize and expand its mainline system and record throughput levels were reached, driven by strong supply and refinery demand in combination with efforts to maximize capacity and throughput and to enhance scheduling efficiency with shippers. The Liquids Pipelines business acquired by EIPLP is expected to have future organic growth opportunities beyond the current inventory of secured projects, which are further discussed in Growth Projects. EIPLP will have a first right to execute any such projects that fall within the footprint of the Canadian Liquids Pipelines business.

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In Gas Pipelines, EIPLP seeks to optimize the competitive advantage of its existing asset footprint, as the Alliance Pipeline is well-positioned to provide liquids-rich gas transportation to developing regions in northeast British Columbia, northwestern Alberta and the Bakken. Alliance Pipeline has successfully re-contracted its firm capacity with shippers under its new services framework that commenced in December 2015. Long-term contracts have been secured through staged and non-staged receipt or full path services with an average contract length of approximately five years. In the brief period since Alliance Pipeline implemented its new services framework, Alliance Pipeline has also seen significant interest in its interruptible and seasonal firm services through its open season process. For further details refer to Gas Pipelines – Alliance Pipeline System – Alliance Pipeline Recontracting. In Green Power, strategies are driven by the objective to manage and maintain facilities in such a way as to maximize power generation and related revenues when the relevant wind, solar or waste heat energy resource is available. The Manager will continue to assess ways to generate value for EIPLP’s partners, including reviewing opportunities that may lead to acquisitions or other strategic transactions, some of which may be material and involve EIPLP’s sponsor, Enbridge. Opportunities are screened, analysed and assessed using strict operating, strategic and financial criteria with the objective of ensuring the effective deployment of capital and the enduring financial strength and stability of EIPLP. FOCUS ON PROJECT MANAGEMENT Enbridge’s enterprise-wide objective is to safely deliver projects on time and on budget and at the lowest practical cost while maintaining the highest standards for safety, quality, customer satisfaction and environmental and regulatory compliance. With the large slate of commercially secured growth projects being undertaken by EIPLP, successful project execution is critical to the success of EIPLP’s strategy. Growth projects across the Enbridge entities, including those being undertaken by EIPLP, are managed centrally by Enbridge’s Major Projects Group (Major Projects). Major Projects continues to build upon and enhance the key elements of its rigorous project management processes including: employee and contractor safety; long-term supply chain agreements; quality design, materials and construction; extensive regulatory and public consultation; robust cost, schedule and risk controls; and efficient project transition to operating units. PRESERVE FINANCING STRENGTH AND FLEXIBILITY The maintenance of adequate financing strength and flexibility is crucial to the growth strategy of EIPLP. Ongoing access to cost effective sources of debt and equity capital is critical to the successful execution of EIPLP’s strategy to expand existing assets and acquire or develop new energy infrastructure. With support from Enbridge and the Fund Group, EIPLP’s financial strategies are designed to ensure it has sufficient financial flexibility to meet its capital requirements. To support this objective, Enbridge and the Fund Group develop financing plans and strategies to manage credit ratings, diversify funding sources and maintain substantial standby bank credit capacity and access to capital markets in both Canada and the United States. As part of Enbridge’s enterprise-wide risk management policy, EIPLP engages in a comprehensive long-term economic hedging program to mitigate the impact of fluctuations in interest rates, foreign exchange and commodity price on EIPLP’s earnings. To the extent that ENF does not fund any portion of the growth capital, Enbridge will be required until December 31, 2020 to provide EIPLP with equity financing for such projects, unless the project is related to the Line 3 Replacement Program in which case Enbridge’s obligation will be to fund the equity requirements for such project until it is placed into service.

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INDUSTRY FUNDAMENTALS SUPPLY AND DEMAND FOR LIQUIDS In the third quarter of 2014, the price of crude oil began a dramatic decline. Benchmark prices for crude, which had been trading over US$105 per barrel in June 2014, fell to as low as US$37 per barrel by the end of 2015, with a further decline to below US$30 in January 2016. The international market for crude oil has seen a significant increase in production from North American basins and increased production from the Organization of Petroleum Exporting Countries (OPEC) in the face of slower global demand growth. The downturn in price has impacted EIPLP’s liquids pipelines’ customers, who have responded by reducing their exploration and development spending for 2015 and into 2016. Notwithstanding the recent price decline, the mainline system has thus far continued to be highly utilized. The mainline system continues to be subject to apportionment of heavy crudes, as nominated volumes currently exceed capacity on portions of the system. Impact of the decline in crude oil prices to the financial performance of EIPLP’s liquids pipelines business is expected to be relatively modest given the commercial arrangements which underpin many of the pipelines that make up the liquids system and provide a significant measure of protection against volume fluctuations. In addition, the mainline system is well positioned to continue to provide safe and efficient transportation which will enable western Canadian and Bakken production to reach attractive markets in the United States at a competitive cost relative to other alternatives. The fundamentals of oil sands production and the recent decline in crude oil prices has caused some sponsors to reconsider the timing of their upstream oil sands development projects; however, recently updated forecasts continue to reflect long-term supply growth from the Western Canadian Sedimentary Basin (WCSB), although the projected pace of growth is slower than previous forecasts as companies continue to assess the viability of certain capital investments in the current low price environment. Over the long term, global energy consumption is expected to continue to grow, with the growth in crude oil demand primarily driven by emerging economies in regions outside the Organization for Economic Cooperation and Development (OECD), mainly China and India. While OECD countries, including Canada, the United States and western European nations will experience population growth, emphasis on energy efficiency, conservation and a shift to lower carbon fuels, such as natural gas and renewables, will reduce crude oil demand over the long term. Accordingly, there is a strategic opportunity for North American producers to grow production to displace foreign imports and participate in the growing global demand outside North America. In terms of supply, long-term global crude oil production is expected to continue to grow through 2035, with growth in supply primarily contributed by North America and OPEC. Growth in North America is largely driven by production from the oil sands, the Gulf of Mexico and the continued development of tight oil plays including the Bakken, Eagle Ford and Permian formations. Growth in supply from OPEC is primarily a result of a shift in OPEC’s strategy from ‘balancing supply’ to ‘competing for market share’ in Asia and Europe. However, political uncertainty in certain oil producing countries, including Libya and Iraq, increases risk in those regions’ supply growth forecasts and makes North America one of the most secure supply sources of crude oil. As witnessed throughout 2015 and early 2016, North American supply growth can be influenced by macro-economic factors that drive down the global crude prices. Over the longer term, North American production from tight oil plays, including the Bakken, is expected to grow as technology continues to improve well productivity and reduces costs. The WCSB, in Canada, is viewed as one of the world’s largest and most secure supply sources of crude oil. However, the pace of growth in North America and level of investment in the WCSB could be tempered in future years by a number of factors including a sustained period of low crude oil prices and corresponding production decisions by OPEC, increasing environmental regulation, prolonged approval processes for new pipelines and the continuation of access restrictions to tide-water in Canada for export. The combination of relatively flat domestic demand, growing supply, limited exports and long-lead time to build pipeline infrastructure has led to a fundamental change in the North American crude oil landscape. In recent years, an inability to move increasing inland supply to tide-water refining markets resulted in a divergence between West Texas Intermediate (WTI) and world pricing, resulting in lower netbacks for

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North American producers than could otherwise be achieved if selling into global markets. The impact of price differentials has been even more pronounced for western Canadian producers as insufficient pipeline infrastructure resulted in a further discounting of Alberta crude against WTI. With a number of market access initiatives recently completed by the industry, including those introduced by Enbridge, the crude oil price differentials significantly narrowed in 2015, and resulted in higher netbacks for producers. This has resulted in crude oil moving off of alternative transportation such as rail to fill the additional pipeline capacity as it became available. However, Canadian pipeline export capacity remains essentially full, and production growth once again is increasing its use of non-pipeline transportation services. As the supply in North America continues to grow, the growth and flexibility of pipeline infrastructure will need to keep pace with the sensitive demand and supply balance. Over the longer term, EIPLP believes pipelines will continue to be the most cost-effective means of transportation in markets where the differential between North American and global oil prices remain narrow. Utilization of rail to transport crude is expected to be substantially limited to those markets not readily accessible by pipelines. As prices continue to remain sensitive to capacity limitations to markets, there is a heightened need to expand access to coastal markets. EIPLP’s and Enbridge’s role in helping to address the evolving supply and demand fundamentals and alleviating price discounts for producers and supply costs to refiners is to provide expanded pipeline capacity and sustainable connectivity to alternative markets. As discussed in Growth Projects, in 2015, EIPLP continued to execute its growth projects plan in furtherance of this objective. SUPPLY AND DEMAND FOR NATURAL GAS AND NGL Experiencing a similar price trend as crude oil, the prices of natural gas and NGL and other commodities whose prices are highly correlated to crude oil have also been declining. Despite the recent slowing of China’s economic growth, global energy demand is expected to increase over time, driven by expected economic growth from non-OECD countries. Natural gas will play an important role in meeting this energy demand and is anticipated to be one of the world’s fastest growing energy sources. Most natural gas demand will stem from the need for greater power generation capacity; natural gas is a cleaner alternative to coal which has the largest market share for power generation. Within North America, United States natural gas demand is also expected to be driven by the next wave of gas-intensive petrochemical facilities which are expected to enter service over the next two years along with the commissioning of the first of several liquefied natural gas (LNG) export facilities in 2016. Over the longer-term, higher United States natural gas demand is expected to be driven by the industrial sector and from power generation and will be supplemented by higher exports, via LNG and to Mexico. Within Canada, natural gas demand growth is expected to be largely tied to oil sands development and growth in gas-fired power generation. Similar to crude oil, robust North American supply from tight formations has created a demand and supply imbalance for natural gas and some NGL products. North American gas supply continues to be significantly impacted by development in the northeastern United States, primarily the prolific Marcellus shale, as well as the rapidly growing Utica shale. The abundance of supply from these shale plays has fundamentally altered natural gas flow patterns in North America. For example, flows from the United States Gulf Coast and WCSB that historically supplied eastern markets, have largely been displaced. Similar pressures are also being felt in the midwest and southern markets. As a result, natural gas production in regions other than the northeastern United States has largely been flat or has declined over the past several years in the face of lower-cost production from the Appalachian region in addition to prolonged weak North American natural gas prices. While low natural gas prices are expected to be a key driver in future natural gas demand and infrastructure growth, it is also expected that gas supply will remain ample and could respond quickly to rising demand thereby limiting price advances. With the weak natural gas price environment over the last several years, producers had broadly shifted from dry gas drilling to developing rich gas reservoirs to take advantage of the relatively higher value of NGL inherent in the gas stream. NGL that can be extracted from liquids-rich gas streams include ethane, propane, butane and natural gasoline, which are used in a variety of industrial, commercial and other applications. However, the combined effects of much lower crude prices and regional supply imbalances for some NGL products have weakened the economics of NGL extraction to the extent that some producers have returned to drilling prolific dry gas plays which exhibit lower supply costs. Nonetheless,

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over the longer-term, the growth in NGL demand is expected to be robust, driven largely by incremental ethane demand. Ethane is the key feedstock to the United States Gulf Coast petrochemical industry which is the world’s second lowest-cost ethylene production region and is currently undergoing significant expansion. However, until this new infrastructure is completed and online, ethane prices and resulting extraction margins are expected to continue to remain low due to the current oversupply with high volumes of ethane being retained in the gas stream rather than extracted. Similarly, rapidly growing supplies of propane have been outpacing demand leading to record storage levels and downward pressure on prices. The outlook for abundant propane supplies in excess of domestic demand has prompted the development and expansion of export facilities for liquefied petroleum gas (LPG). Over a few short years, the United States has become the world’s largest LPG exporter. In Canada, the WCSB basin is well-situated to capitalize on the evolving NGL fundamentals over the longer term as the Montney formation in northern British Columbia and the Duvernay shale in Alberta contain significant liquids-rich resources at competitive extraction costs. While longer term NGL fundamentals provide a positive outlook for growth, a sustained period of low crude oil prices and the related negative impact on NGL prices could temper future growth. Weak prices for NGL, which generally trade at a percentage of crude oil prices, have also caused a reduction in investment for liquids-rich gas drilling programs and related extraction facilities, thereby limiting production growth. However, robust gas production from highly economic core areas within certain shale plays, particularly the Marcellus, is expected to continue to offset any price related production declines from other supply regions over the next year. To the extent oil prices recover, the crude-to-gas price ratio is expected to rise from current levels. The immense and readily available gas supply within North America will likely continue to limit price increases. Consequently, the crude-to-gas price ratio is expected to remain well above energy conversion value levels and continue to be supportive of NGL extraction over the longer term. In response to these evolving natural gas and NGL fundamentals, the Manager believes EIPLP is well-positioned to provide value-added solutions to producers. Alliance Pipeline traverses through the heart of key liquids-rich plays in the WCSB and is uniquely positioned to transport liquids-rich gas. Alliance Pipeline has developed new service offerings to best meet the needs of producers and shippers and demand for transportation services on the Alliance Pipeline continues to be robust. SUPPLY AND DEMAND FOR RENEWABLE ENERGY The power generation and transmission network in North America is expected to undergo significant growth over the next 20 years. On the demand side, North American economic growth over the longer-term is expected to drive growing electricity demand, although continued efficiency gains are expected to make the economy less energy-intensive and temper demand growth. On the supply side, impending legislation in both Canada and the United States is expected to accelerate the retirement of aging coal-fired generation plants, resulting in a requirement for significant new generation capacity. While coal and nuclear facilities will continue to be core components of power generation in North America, gas-fired and renewable energy facilities, including biomass, hydro, solar and wind, are expected to be the preferred sources to replace coal-fired generation due to their lower carbon intensities. North American wind and solar resources fundamentals remain strong. In the United States there is over 74 gigawatts (GW) of installed wind power capacity and in Canada over 11 GW of capacity. Solar resources in southwestern states such as Arizona, California and Nevada are considered to be some of the best in the world for large-scale solar plants and the United States currently has over 24 GW of installed solar photovoltaic capacity. In addition, in late 2015, the United States passed legislation extending the availability of certain Federal tax incentives which have supported the profitability of wind and solar projects. However, expanding renewable energy infrastructure in North America is not without challenges. Growing renewable generation capacity is expected to necessitate substantial capital investment to upgrade existing transmission systems or, in many cases, build new transmission lines, as these high quality wind and solar resources are often found in regions that are not in close proximity to markets. In the near-term, uncertainty over the continuing availability of tax or other government incentives and the ability to secure long-term power purchase agreements (PPA) through government or investor-owned power authorities and low market prices of electricity may hinder the pace of future new

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renewable capacity development. However, continued improvement in technology and manufacturing capacity in the past few years has reduced capital costs associated with renewable energy infrastructure and has also improved yield factors of power generation assets. These positive developments are expected to render renewable energy more competitive and support ongoing investment over the long term. EIPLP has interests in 1,052 MW of net renewable energy generation and together with Enbridge, its sponsor, it will continue to seek new opportunities to expand its power generation business, growing its portfolio by investing in assets that meet its investment criteria. GROWTH PROJECTS As part of the 2015 Transaction, the commercially secured growth programs embedded within EPI and EPAI were transferred to EIPLP. Enbridge and the Manager continue to oversee the execution of these projects, as well as manage the operations and future development opportunities for EPI and EPAI. The following table summarizes the current status of the commercially secured projects. The estimated capital costs and the expenditures to date are inclusive of costs incurred prior to the closing of the 2015 Transaction, with the majority of the expenditures to date incurred prior to the close of the 2015 Transaction.

Estimated

Capital Cost1 Expenditures

to Date2

Expected In-Service

Date Status (Canadian dollars, unless stated otherwise) LIQUIDS PIPELINES 1. Eastern Access Line 9 Reversal and

Expansion $0.8 billion $0.8 billion 2013-2015

(in phases) Complete

2. Canadian Mainline Expansion3 $0.7 billion $0.7 billion 2015 Complete

3. Surmont Phase 2 Expansion3 $0.3 billion $0.3 billion 2014-2015 (in phases)

Complete

4. Canadian Mainline System Terminal Flexibility and Connectivity3

$0.7 billion $0.7 billion 2013-2015 (in phases)

Complete

5. Woodland Pipeline Extension3 $0.7 billion $0.7 billion 2015 Complete

6. Sunday Creek Terminal Expansion3 $0.2 billion $0.2 billion 2015 Complete

7. Edmonton to Hardisty Expansion $1.6 billion $1.6 billion 2015 (in phases)

Complete

8. AOC Hangingstone Lateral $0.2 billion $0.2 billion 2015 Complete

9. JACOS Hangingstone Project $0.2 billion $0.1 billion 2016 Under construction

10. Regional Oil Sands Optimization Project

$2.6 billion $1.6 billion 2017 Under construction

11. Norlite Pipeline System4 $1.3 billion $0.2 billion 2017 Under construction

12. Canadian Line 3 Replacement Program

$4.9 billion $0.9 billion 2019 Pre- construction

1 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect EIPLP’s share of joint venture projects.

2 Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2015. 3 These projects were completed prior to the closing of the 2015 Transaction. 4 EIPLP will construct and operate the Norlite Pipeline System (Norlite). Keyera Corp. (Keyera) will fund 30% of the project. Risks related to the development and completion of growth projects are described under Risk Management and Financial Instruments – General Business Risks.

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LIQUIDS PIPELINES Eastern Access The Eastern Access initiative includes a series of crude oil pipeline projects being undertaken by Enbridge and EEP, an affiliate of EIPLP, to provide increased access to refineries in the upper midwest United States and eastern Canada. Projects undertaken by Enbridge include a reversal of Line 9A and expansion of the Toledo Pipeline, both completed in 2013, as well as the reversal of Line 9B and expansion of Line 9 (together, Line 9), which was placed into service in December 2015. Enbridge completed the reversal of its 240,000 barrels per day (bpd) Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in that province. The Line 9B reversal was initially expected to be completed at an estimated cost of approximately $0.3 billion. Following an open season held on the Line 9B reversal project, further commitments were received that required additional delivery capacity into Ontario and Quebec, resulting in the Line 9 capacity expansion project. The Line 9 capacity expansion increased the annual capacity of Line 9 from 240,000 bpd to 300,000 bpd at an estimated cost of approximately $0.1 billion. The Line 9B Reversal and Line 9 Capacity Expansion projects were approved by the National Energy Board (NEB) in March 2014 subject to 30 conditions. In October 2014, the NEB requested additional information regarding one of the conditions imposed on the Line 9B Reversal and Line 9 Capacity Expansion Project. On October 23, 2014, Enbridge responded to the NEB describing its rigorous approach to risk management and isolation valve placement. On February 6, 2015, the NEB approved Conditions 16 and 18, the two conditions in the NEB’s order requiring approval, and Enbridge filed for a Leave to Open (LTO), which is a prerequisite to allowing the operation of the project. In its February approval, the NEB also imposed additional obligations on Enbridge that directed it to take a “life-cycle” approach to water crossings and valves, requiring it to perform ongoing analysis to ensure optimal protection of the area’s water resources. On June 18, 2015, the NEB approved the LTO application and issued a separate order imposing further conditions requiring Enbridge to perform hydrostatic tests of selected segments of the pipeline. Enbridge filed its hydrostatic test plan with the NEB on July 23, 2015, which was approved on July 27, 2015. Hydrostatic testing was completed and Enbridge submitted the test results to the NEB in September 2015. On September 30, 2015 the NEB confirmed that the hydrostatic tests successfully met their criteria. Line-fill commenced in late October 2015 and the pipeline was placed into service in December 2015. Costs related to conditions imposed by the NEB, including valve placement and hydrostatic testing, increased the total project cost at in-service to $0.8 billion, inclusive of costs related to the previously mentioned Line 9A reversal. Pursuant to various agreements with shippers, EIPLP is able to recover from shippers the full costs of compliance with NEB imposed hydrostatic testing and the valve replacement program. On July 31, 2014, Enbridge filed an application for tolls on Line 9. After complaints from shippers on Line 9 were filed with the NEB with respect to the inclusion of mainline surcharges in the Line 9 toll, the NEB approved the tolls on an interim basis to allow for time to engage shippers in further discussions to attempt to resolve the outstanding issues. On January 30, 2015, the NEB convened a hearing to consider the matter. In response to a request from Enbridge that was supported by the shippers, the hearing was suspended to allow Enbridge and shippers to engage in further discussions to resolve the outstanding issues. In the third quarter of 2015, Enbridge and the shippers came to an agreement to recover mainline surcharges in the Line 9 toll.

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Canadian Mainline Expansion Enbridge undertook an expansion of the Alberta Clipper line between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba. The scope of the project consisted of two phases that involved the addition of pumping horsepower to raise the capacity of the Alberta Clipper line from 450,000 bpd to 800,000 bpd. The initial phase to increase capacity from 450,000 bpd to 570,000 bpd was completed in the third quarter of 2014 at an estimated capital cost of approximately $0.2 billion. The second phase to increase capacity from 570,000 bpd to 800,000 bpd was completed in July 2015 at an expected cost of approximately $0.5 billion. The total cost of the entire expansion was approximately $0.7 billion. Receipt of the final regulatory approval on EEP’s portion of the mainline system expansion has been delayed. EEP continues to work with regulatory authorities; however, the timing of the federal regulatory approval cannot be determined at this time. A number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with this delay. Surmont Phase 2 Expansion In 2013, Enbridge entered into a terminal services agreement with ConocoPhillips Canada Resources Corp. (ConocoPhillips) and Total E&P Canada Ltd. (together, the ConocoPhillips Partnership) to expand the Cheecham Terminal to accommodate incremental bitumen production from Surmont’s Phase 2 expansion. Enbridge constructed two new 450,000 barrel blend tanks and converted an existing tank from blend to diluent service. The expansion occurred in two phases with the blended product system placed into service in November 2014 and the diluent system placed into service in March 2015 at a total cost of approximately $0.3 billion. Canadian Mainline System Terminal Flexibility and Connectivity As part of the Light Oil Market Access Program initiative, Enbridge undertook the Canadian Mainline System Terminal Flexibility and Connectivity project in order to accommodate additional light oil volumes and enhance the operational flexibility of the Canadian mainline terminals. The modifications comprised of upgrading existing booster pumps, installing additional booster pumps and adding new tank line connections. These projects had varying completion dates from 2013 through the second quarter of 2015. The total cost of the project was approximately $0.7 billion. Woodland Pipeline Extension The joint venture Woodland Pipeline Extension Project extended the Woodland Pipeline south from the Cheecham Terminal to the Edmonton Terminal. The extension is a 388-kilometre (241-mile), 36-inch diameter pipeline with an initial capacity of 400,000 bpd, expandable to 800,000 bpd. The project was completed and placed into service in July 2015. Enbridge’s share of the project costs was approximately $0.7 billion. Sunday Creek Terminal Expansion In 2014, Enbridge announced the construction of additional facilities at its existing Sunday Creek Terminal, located in the Christina Lake area of northern Alberta, to support production growth from the Christina Lake oil sands project operated by Cenovus Energy Inc. and jointly owned with ConocoPhillips. The expansion included development of a new site adjacent to the existing terminal, construction of a new 350,000 barrel tank with associated piping, pumps and measurement equipment, as well as civil construction work for a future tank. The project was placed into service in August 2015 at an approximate cost of $0.2 billion. Edmonton to Hardisty Expansion The expansion of the Canadian Mainline system between Edmonton, Alberta and Hardisty, Alberta included 181 kilometres (112 miles) of new 36-inch diameter pipeline and provides an initial capacity of approximately 570,000 bpd, expandable to 800,000 bpd. The new line generally follows the same route as EIPLP’s existing Line 4 pipeline. Also included in the project scope were connections into existing infrastructure at the Hardisty Terminal and new terminal facilities in Edmonton, Alberta which include five new 500,000 barrel tanks. The new pipeline was placed into service in April 2015, with additional tankage requirements completed in December 2015. The project was placed into service at a cost approximately $1.6 billion.

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AOC Hangingstone Lateral In 2013, Enbridge entered into an agreement with Athabasca Oil Corporation (AOC) to provide pipeline and terminalling services to the proposed AOC Hangingstone Oil Sands Project (AOC Hangingstone) in Alberta. Phase I of the project involved the construction of a new 49-kilometre (31-mile), 16-inch diameter pipeline from the AOC Hangingstone project site to EIPLP’s newly acquired Cheecham Terminal and related facility modifications at Cheecham, Alberta. This phase of the project provides an initial capacity of 16,000 bpd and was placed into service in December 2015 at a cost of approximately $0.2 billion. Phase 2 of the project, which is subject to commercial approval, would provide up to an additional 60,000 bpd for a total capacity of 76,000 bpd. JACOS Hangingstone Project EIPLP is undertaking the construction of facilities and it will provide transportation services to the Japan Canada Oil Sands Limited (JACOS) Hangingstone Oil Sands Project (JACOS Hangingstone). JACOS and Nexen Energy ULC, a wholly-owned subsidiary of China National Offshore Oil Corporation Limited, are partners in the project which is operated by JACOS. EIPLP is constructing a new 53-kilometre (33-mile), 12-inch lateral pipeline to connect the JACOS Hangingstone project site to EIPLP’s newly acquired Cheecham Terminal. The project, which will provide capacity of 40,000 bpd, is expected to enter service by the end of 2016. The estimated cost of the project is approximately $0.2 billion, with expenditures to date of approximately $0.1 billion. Regional Oil Sands Optimization Project In March 2015, Enbridge announced a plan to optimize previously announced expansions of the Regional Oil Sands System currently in execution. Enbridge previously announced the Wood Buffalo Extension, which includes the construction of a 30-inch pipeline, from the Cheecham Terminal to the Battle River Terminal at Hardisty, Alberta and associated terminal upgrades, and the Athabasca Pipeline Twin, which consists of the twinning of the southern section of the Athabasca Pipeline with a 36-inch diameter pipeline from Kirby Lake, Alberta to the Hardisty crude oil hub. The optimization plan, which has been agreed to with the affected shippers, including Suncor Energy Inc., Total E&P Canada Ltd. and Teck Resources Limited (the Fort Hills Partners), will enable deferral of the southern segment of the Wood Buffalo Extension by connecting it to the Athabasca Pipeline Twin. The optimization involves the upsize of a 100-kilometre (60-mile) segment of the Wood Buffalo Extension between Cheecham, Alberta and Kirby Lake, Alberta from a 30-inch diameter pipeline to a 36-inch diameter pipeline, which will now connect to the origin of the Athabasca Pipeline Twin at Kirby Lake, Alberta. The capacity of the Athabasca Pipeline Twin will be expanded from 450,000 bpd to 800,000 bpd through additional horsepower. The definitive cost estimate of the Wood Buffalo Extension was finalized at approximately $1.8 billion before optimization. As a result of the optimization, the cost estimate to complete the integrated Wood Buffalo Extension and Athabasca Pipeline Twin projects is expected to decrease from approximately $3.0 billion to approximately $2.6 billion. Expenditures on the joint projects to date are approximately $1.6 billion. The integrated Wood Buffalo Extension and Athabasca Pipeline Twin will transport diluted bitumen from the proposed Fort Hills Partners’ oil sands project (Fort Hills Project) in northeastern Alberta, as well as from oil sands production from Suncor Energy Oil Sands Limited Partnership (Suncor Partnership) in the Athabasca region. The Wood Buffalo Extension and the Athabasca Pipeline Twin will ship blended bitumen from the Fort Hills Project and have an expected 2017 in-service date. The Athabasca Pipeline Twin will also ship blended bitumen from the Cenovus Christina Lake Steam Assisted Gravity Drainage project near the origin of the Athabasca Pipeline Twin.

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Norlite Pipeline System Enbridge is undertaking the development of Norlite, a new industry diluent pipeline originating from Edmonton, Alberta to meet the needs of multiple producers in the Athabasca oil sands region. The scope of the project was increased to a 24-inch diameter pipeline, which will provide an initial capacity of approximately 224,000 bpd of diluent, with the potential to be further expanded to approximately 400,000 bpd of capacity with the addition of pump stations. Norlite will be anchored by throughput commitments from the Fort Hills Partners for production from the proposed Fort Hills Project and from Suncor Partnership’s proprietary oil sands production. Norlite will involve the construction of a new 449-kilometre (278-mile) pipeline from EIPLP’s Stonefell Terminal to its Cheecham Terminal with an extension to Suncor Partnership’s East Tank Farm, which is adjacent to EIPLP’s Athabasca Terminal. Under an agreement with Keyera, Norlite has the right to access certain existing capacity on Keyera’s pipelines between Edmonton, Alberta and Stonefell, Alberta and, in exchange, Keyera has elected to participate in the new pipeline infrastructure project as a 30% non-operating owner. Norlite is expected to be completed in 2017 at an estimated cost of approximately $1.3 billion, with expenditures to date of approximately $0.2 billion. Canadian Line 3 Replacement Program In 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. The Canadian L3R Program will complement existing integrity programs by replacing approximately 1,084 kilometres (673 miles) of the remaining line segments of the existing Line 3 pipeline between Hardisty, Alberta and Gretna, Manitoba. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it will support the safety and operational reliability of the overall system, enhance flexibility and allow EIPLP to optimize throughput on the mainline system’s overall western Canada export capacity. The L3R Program is expected to achieve capacity of approximately 760,000 bpd. With the NEB hearing for the Canadian L3R Program application ending in December 2015, the application record is now closed with Final Conditions and a recommendation to the Federal Cabinet (the Cabinet) expected by the end of the first quarter of 2016. A decision by the Cabinet was expected to be issued by July 2016 per guidelines; however, Enbridge is awaiting confirmation following the Federal Government’s January 27, 2016 announcement that outside of the NEB process for industry projects, it has directed Federal agencies to conduct assessments of direct and upstream greenhouse gas emissions and incremental consultation with affected communities and Indigenous peoples. Depending on the scope of this new process, the expected timeline for final regulatory approval to commence construction could be extended. Enbridge has reached a settlement agreement with landowner associations representing Line 3 landowners in Canada and as a result these parties have withdrawn from the hearing process and have expressed their support for the project. Subject to regulatory and other approvals, the Canadian L3R Program is now targeted to be completed in early 2019 at an estimated capital cost of approximately $4.9 billion, with expenditures to date of approximately $0.9 billion. With a delay in construction, the cost of this project is expected to increase. Enbridge continues to review the estimated cost of this project. Costs of the Canadian L3R Program will be recovered through a 15-year toll surcharge mechanism under the CTS.

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LIQUIDS PIPELINES EARNINGS BEFORE INTEREST AND INCOME TAXES 2015 2014 2013 (millions of Canadian dollars) Canadian Mainline 355 - - Regional Oil Sands System 124 - - Southern Lights Pipeline 77 6 - Feeder Pipelines and Other 84 75 73 Adjusted earnings before interest and income taxes 640 81 73 Retrospective adjustment - 2015 Transaction1 (324) 491 596 Canadian Mainline - changes in unrealized derivative fair value loss (272) - - Canadian Mainline - Line 9B costs incurred during reversal 1 - - Regional Oil Sands System - leak insurance recoveries 22 - - Regional Oil Sands System - make-up rights adjustment (5) - -

Southern Lights Pipeline - changes in unrealized derivative fair value

loss (87) (19) - Southern Lights Pipeline - realized gain on subscription price - 22 - Feeder Pipelines and Other - gain on sale 22 - - Feeder Pipelines and Other - make-up rights adjustment 2 - (3) Feeder Pipelines and Other - derecognition of regulatory balances - - (17) Feeder Pipelines and Other - non-cash project costs write-off - - (2) Earnings/(loss) before interest and income taxes (1) 575 647 1 In accordance with U.S. GAAP, EBIT have been retrospectively adjusted to reflect the 2015 Transaction prior to the effective

date of the transaction. The impact of the retrospective adjustments has been removed from adjusted EBIT to reflect earnings generated under EIPLP’s ownership prior to September 1, 2015.

Additional details on items impacting Liquids Pipelines EBIT include:

• Canadian Mainline EBIT for 2015 reflected changes in unrealized fair value losses primarily on derivative financial instruments used to risk manage exposures inherent within the CTS, namely foreign exchange, power cost variability and allowance oil commodity prices.

• Regional Oil Sands System EBIT for 2015 included insurance recoveries associated with the Line 37 crude oil release, which occurred in June 2013. Refer to Liquids Pipelines – Regional Oil Sands System – Line 37 Crude Oil Release.

• Southern Lights Pipeline EBIT for each period reflected changes in unrealized fair value gains and losses on derivative financial instruments used to risk manage foreign exchange exposures on United States dollar cash flows from the Southern Lights Class A Units.

• Feeder Pipelines and Other earnings for the year ended December 31, 2015 reflected a gain on the disposition of certain crude oil pipeline assets from the Virden System in the second quarter of 2015.

Liquids Pipelines adjusted EBIT for the year ended December 31, 2015 increased compared with the corresponding 2014 and 2013 periods, as a result of the incremental earnings from the assets acquired, most notably the Canadian Mainline and Regional Oil Sands System, as part of the 2015 Transaction. Refer to Canadian Restructuring Plan. CANADIAN MAINLINE The Canadian Mainline is a common carrier pipeline system which transports various grades of oil and other liquid hydrocarbons within western Canada and from western Canada to the Canada/United States border near Gretna, Manitoba and Neche, North Dakota and from the United States/Canada border near Port Huron, Michigan and Sarnia, Ontario to eastern Canada and the northeastern United States. The Canadian Mainline includes six adjacent pipelines, with a combined design operating capacity of approximately 2.85 million bpd that connect with the Lakehead System at the Canada/United States border, as well as four crude oil pipelines and one refined products pipeline that deliver into eastern Canada and the northeastern United States. It also includes certain related pipelines and infrastructure,

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including decommissioned and deactivated pipelines. EPI, now a wholly-owned subsidiary of EIPLP, has operated, and frequently expanded, the Canadian Mainline since 1949. Competitive Toll Settlement The CTS is the current framework governing tolls paid for products shipped on the Canadian Mainline, with the exception of Lines 8 and 9 which are tolled on a separate basis. The 10-year settlement was negotiated by representatives of EPI, the Canadian Association of Petroleum Producers and shippers on the Canadian Mainline. It was approved by the NEB on June 24, 2011 and took effect on July 1, 2011. The CTS provides for a Canadian Local Toll (CLT) for deliveries within western Canada, which is based on the 2011 Incentive Tolling Settlement toll, as well as an IJT for crude oil shipments originating in western Canada on the Canadian Mainline and delivered into the United States, via the Lakehead System, and into eastern Canada. These tolls are denominated in United States dollars. The IJT is designed to provide shippers on the Canadian Mainline with a stable and competitive long-term toll, thereby preserving and enhancing throughput on both the Canadian Mainline and the Lakehead System. The IJT and the CLT were both established at the time of implementation of the CTS and are adjusted annually, on July 1 of each year, at a rate equal to 75% of the Canada Gross Domestic Product at Market Price Index published by Statistics Canada. Certain events may trigger a renegotiation of the CTS by EPI or the shippers. These include (i) a regulatory change that results in cumulative capital expenditures for integrity work on the Canadian Mainline increasing by more than $100 million, or (ii) if the nine month average volume on the Canadian Mainline, ex-Gretna, Manitoba, falls below the minimum threshold volume (currently 1.35 million bpd). If a renegotiation of the CTS is triggered, EPI and the shippers will meet and use reasonable efforts to agree on how the CTS can be amended to accommodate the event. If EPI and the shippers are unable to agree on the manner in which the CTS is to be amended, then, absent an extension to the renegotiation period, the CTS will terminate and EPI will need to file a new toll application for the Canadian Mainline. Two years prior to the end of the term of the CTS, EPI and the shippers will establish a group for the purposes of negotiating a new settlement to replace the CTS once it expires. Although the CTS has a 10 year term, it does not require shippers to commit to certain volumes. Shippers nominate volumes on a monthly basis and EPI allocates capacity to maximize the efficiency of the Canadian Mainline. Local tolls for service on the Lakehead System are not affected by the CTS and continue to be established pursuant to the Lakehead System’s existing toll agreements. Under the terms of the IJT agreement between Enbridge and EEP, the Canadian Mainline’s share of the IJT toll relating to pipeline transportation of a batch from any western Canada receipt point to the United States border is equal to the IJT toll applicable to that batch’s United States delivery point less the Lakehead System’s local toll to that delivery point. This amount is referred to as the Canadian Mainline IJT Residual Benchmark Toll and is denominated in United States dollars. Results of Operations Canadian Mainline adjusted EBIT for the year ended December 31, 2015 reflected earnings from the acquisition of the Canadian Mainline on September 1, 2015 as part of the 2015 Transaction. Canadian Mainline EBIT is largely driven by throughput achieved on the mainline system. During 2015, throughput on the Canadian Mainline was stronger largely due to strong oil sands production, as well as ongoing efforts to optimize capacity utilization and to enhance scheduling efficiency with shippers. However, further throughput growth in late third and fourth quarters of 2015 was hindered by upstream plant maintenance in Alberta which impacted light volumes and an unplanned shutdown of a midwest refinery that impacted the takeaway of heavy volumes, although these effects were alleviated towards the latter part of the fourth quarter of 2015. Canadian Mainline fourth quarter adjusted EBIT also reflected one month of revenues from Line 9B which was placed into service in December 2015.

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Throughput Volume Canadian Mainline throughput volume represents deliveries ex-Gretna, Manitoba, which is made up of United States and eastern Canada deliveries entering the Canadian Mainline in western Canada.

Q3 2015 Q4 2015 Full year

2015 (thousands of bpd) Average throughput volume1 2,221 2,243 2,238 1 Throughput volumes are representative of EIPLP’s ownership period of the Canadian Mainline. REGIONAL OIL SANDS SYSTEM Regional Oil Sands System includes three long haul pipelines, the Athabasca Pipeline, Waupisoo Pipeline and Woodland Pipeline, and two large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta and the Cheecham Terminal, located 70 kilometres (45 miles) south of Fort McMurray where the Waupisoo Pipeline initiates. Regional Oil Sands System also includes the Wood Buffalo Pipeline and Norealis Pipeline, each of which provides access for oil sands production from near Fort McMurray to the Cheecham Terminal. The recently completed Woodland Pipeline extension project further extended the Woodland Pipeline south from EIPLP’s Cheecham Terminal to its Edmonton Terminal. Regional Oil Sands System also includes a variety of other facilities such as the MacKay River, Christina Lake, Surmont, Long Lake and AOC laterals and related facilities. Regional Oil Sands System currently serves eight producing oil sands projects. The Athabasca Pipeline is a 540-kilometre (335-mile) synthetic and heavy oil pipeline. Built in 1999, it links the Athabasca oil sands in the Fort McMurray region to the major Alberta pipeline hub at Hardisty, Alberta. The Athabasca Pipeline’s capacity is 570,000 bpd depending on the viscosity of crude being shipped. EIPLP has long-term take-or pay and non take-or-pay agreements with multiple shippers on the Athabasca Pipeline. Revenues are recorded based on the contract terms negotiated with the major shippers, rather than the cash tolls collected. The Waupisoo Pipeline is a 380-kilometre (236-mile) synthetic and heavy oil pipeline that entered service in 2008 and provides access to the Edmonton market for oil sands producers. The Waupisoo Pipeline originates at the Cheecham Terminal and terminates at the major Alberta pipeline hub at Edmonton. The pipeline has a capacity of 550,000 bpd, depending on crude slate. EIPLP has long-term take-or-pay commitments with multiple shippers on the Waupisoo Pipeline who have collectively contracted for 80% to 90% of the capacity, subject to some short-term variability dependent on the timing of when certain shippers’ commitments expire and commence. Results of Operations Regional Oil Sands System adjusted EBIT for the year ended December 31, 2015 reflected earnings from the acquisition of Regional Oil Sands System on September 1, 2015 as part of the 2015 Transaction. Line 37 Crude Oil Release On June 22, 2013, Enbridge reported a release of light synthetic crude oil on its Line 37 pipeline approximately two kilometres north of the Cheecham Terminal. Line 37 connects facilities in the Long Lake area to the Cheecham Terminal. Enbridge estimated the volume of the release at approximately 1,300 barrels, caused by unusually high water levels in the region that triggered ground movement on the right-of-way. The oil released from Line 37 was recovered and on July 11, 2013, Line 37 returned to service at reduced operating pressure. Normal operating pressure was restored on Line 37 on July 29, 2013 after finalization of geotechnical analysis. As a precaution, on June 22, 2013, Enbridge shut down the pipelines that share a corridor with Line 37, including the Athabasca, Waupisoo, Wood Buffalo and Woodland pipelines. Following extensive engineering and geotechnical analysis, all of the lines except Woodland Pipeline were returned to service by July 19, 2013. The Woodland Pipeline had been in the process of line fill at the time of the shutdown; line fill activities were completed in the third quarter of 2013.

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For the years ended December 31, 2015, 2014 and 2013, EIPLP’s EBIT reflected remediation and long-term stabilization costs of approximately $6 million, $6 million and $75 million before insurance recoveries, respectively. Lost revenues associated with the shutdown of Line 37 and the pipelines sharing a corridor with Line 37 were minimal. At the time of the Line 37 crude oil release, Enbridge carried liability insurance for sudden and accidental pollution events, subject to a $10 million deductible. The integrity and stability costs associated with remediating the impact of the high water levels were precautionary in nature and not covered by insurance. Enbridge expects to record receivables for amounts claimed for recovery pursuant to its insurance policies during the period that it deems realization of the claim for recovery to be probable. For the years ended December 31, 2015 and 2014, insurance recoveries of $32 million and $11 million were recognized in EIPLP’s EBIT in connection with the Line 37 crude oil release. Recoveries of $22 million were received subsequent to the 2015 Transaction. On February 1, 2016, Enbridge was notified that the provincial government agency had completed and closed its investigation on this matter. SOUTHERN LIGHTS PIPELINE Southern Lights Pipeline is a fully-contracted single stream pipeline that ships diluent from the Manhattan Terminal near Chicago, Illinois to three western Canadian delivery facilities, located at the Edmonton and Hardisty terminals in Alberta and the Kerrobert terminal in Saskatchewan. This 180,000 bpd 16/18/20-inch diameter pipeline was placed into service on July 1, 2010. Prior to the close of the 2015 Transaction, Southern Lights Canada was owned by SL Canada, an Alberta limited partnership. Southern Lights US is owned by Enbridge Pipelines (Southern Lights) L.L.C., a Delaware limited liability company. Both Southern Lights Canada and Southern Lights US receive tariff revenues under long-term contracts with committed shippers. Tariffs provide for recovery of all operating and debt financing costs plus a return on equity (ROE) of 10%. The Southern Lights Pipeline has assigned 10% of the capacity (18,000 bpd) for shippers to ship uncommitted volumes. On November 7, 2014, wholly-owned subsidiaries of EIPLP subscribed for and purchased the Southern Lights Class A Units which provide a defined cash flow stream and represent the equity cash flows derived from the core rate base of the Southern Lights Pipeline until June 30, 2040. Payments are received quarterly, each of which is comprised of return on and return of capital components. The return on capital is included in income for the period and the return of capital reduces the balance of the investment on the Consolidated Statements of Financial Position. Enbridge guaranteed payment of the distributions except in circumstances of force majeure, certain regulatory actions and shipper defaults that remain unrecovered under the shipper contracts. EIPLP has options to negotiate extensions for two additional 10-year terms beyond 2040 and to participate in equity returns from future expansions of the Southern Lights Pipeline. Following the close of the 2015 Transaction, EIPLP indirectly owns all of the Class B Units of Southern Lights Canada, together with the Class A Units it already owned. As a result EIPLP holds all the ownership, economic interests and voting rights, direct and indirect, in Southern Lights Canada. The Enbridge guarantee provided in respect of distributions on the Class A Units of Southern Lights Canada was released upon closing of the 2015 Transaction. EIPLP did not acquire any additional direct or indirect interests in Southern Lights US pursuant to the 2015 Transaction. Following closing, EIPLP continues to indirectly own all of the Class A Units of Southern Lights US and Enbridge continues to indirectly own all of the Class B Units of Southern Lights US. Results of Operations Southern Lights adjusted EBIT for the year ended December 31, 2015 primarily reflected earnings in respect of the Southern Lights Class A Units following the close of the 2014 Transaction in November 2014. The majority of the economic benefit derived from the Southern Lights Pipeline resulted from the 2014 Transaction as the Class A Units provide a defined cash flow stream to EIPLP for Southern Lights US and Southern Lights Canada prior to the 2015 Transaction. However, as discussed above, following

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the completion of the 2015 Transaction, Southern Lights Canada’s results are consolidated and reflected in adjusted EBIT for the last four months of 2015. FEEDER PIPELINES AND OTHER Feeder Pipelines and Other includes the South Prairie Region which transports crude oil and NGL from producing fields and facilities in southeastern Saskatchewan, southwestern Manitoba and North Dakota to Cromer, Manitoba where products enter the mainline system to be transported to the United States or eastern Canada. Also included in Feeder Pipelines and Other are related terminals and tankage facilities in Saskatchewan and the Hardisty Contract Terminal and Hardisty Storage Caverns located near Hardisty, Alberta, a key crude pipeline hub in Western Canada. Results of Operations Feeder Pipelines and Other adjusted EBIT increased for the year ended December 31, 2015 compared with the corresponding 2014 and 2013 periods, reflecting higher throughput in 2015 from the South Prairie Region. This was driven by volumes returning to the system from alternative transportation sources, such as rail, as alternative sources were not as competitive as in the corresponding periods. The 2014 increase to adjusted EBIT was partially offset by an unrealized inventory writedown as a result of lower crude oil prices. In addition, earnings in 2015 reflected incremental earnings from the Cromer Rail Interconnection project within the South Prairie Region, which was completed and placed into service during the year. BUSINESS RISKS The risks identified below are specific to the Liquids Pipelines business. General risks that affect EIPLP as a whole are described under Risk Management and Financial Instruments – General Business Risks. Asset Utilization EIPLP is exposed to throughput risk under the CTS on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets and the Lakehead Mainline System owned by EEP. A decrease in volumes transported can directly and adversely affect revenues and earnings. Factors such as changing market fundamentals, capacity bottlenecks, operational incidents, regulatory restrictions, system maintenance and increased competition can all impact the utilization of the Liquids Pipelines assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative energy sources and global supply disruptions outside of EIPLP’s control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on EIPLP’s pipelines. However, the long-term outlook for Canadian crude oil production indicates a growing source of potential supply of crude oil. Interdependence with the Lakehead System Enbridge’s mainline system is an integrated system which transports liquids hydrocarbons between receipt and delivery points across Canada and the United States. The integration of the Canadian Mainline and the Lakehead System results in an interdependence of the two systems, such that operational factors on one system may impact the other system. Such factors may include, but are not limited to, volume throughput increases or decreases, capacity bottlenecks, operational incidents, regulatory restrictions or system maintenance. Any such factor, individually, in combination or over a prolonged period of time, could have a material adverse effect on cash flows or the financial condition of EIPLP and therefore could impact distributions. The CTS framework also results in the Lakehead System having an impact on revenues generated by the Canadian Mainline. Since the Lakehead System local tolls are determined under a tolling agreement which is separate from CTS, changes in the Canadian Mainline IJT Residual Benchmark Toll are inversely related to Lakehead System local tolls. Operational and Economic Regulation Operational regulation risks relate to failing to comply with applicable operational rules and regulations from government organizations and could result in fines or operating restrictions or an overall increase in operating and compliance costs.

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Regulatory scrutiny over the integrity of liquids pipelines assets has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on EIPLP’s future earnings and the cost related to the construction of new projects. EIPLP and the Manager believe operational regulation risk is mitigated by active monitoring and consulting on potential regulatory requirement changes with the respective regulators or through industry associations. EIPLP also develops robust response plans to regulatory changes or enforcement actions. While the Manager believes the safe and reliable operation of its assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators to make unilateral decisions that could have a financial impact on EIPLP. EIPLP’s liquids pipelines also face economic regulatory risk. Broadly defined, economic regulation risk is the risk regulators or other government entities change or reject proposed or existing commercial arrangements including permits and regulatory approvals for new projects. The Canadian Mainline and other liquids pipelines are subject to the actions of various regulators, including the NEB, with respect to the tariffs and tolls of those operations. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on EIPLP’s revenues and earnings. Delays in regulatory approvals could result in cost escalations and constructions delays, which also negatively impact EIPLP’s operations. The Manager believes that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers that govern the majority of EIPLP’s liquids pipelines assets. The Manager also involves its legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations as well as in the establishment of tariffs and tolls on new and existing pipelines. However, despite the efforts to mitigate economic regulation risk, there remains a risk that a regulator could overturn long-term agreements between EIPLP and shippers or deny the approval and permits for new projects. Competition Competition may result in a reduction in demand for EIPLP’s services, fewer project opportunities or assumption of risk that results in weaker or more volatile financial performance than expected. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. Other competing carriers available to ship western Canadian liquid hydrocarbons to markets in Canada and the United States represent competition to Enbridge’s liquids pipelines network, including those held by EIPLP. Competition also arises from proposed pipelines that seek to access markets currently served by Enbridge’s liquids pipelines, such as proposed projects to eastern markets. Competition also exists from proposed projects enhancing infrastructure in the Alberta regional oil sands market. Additionally, volatile crude price differentials and insufficient pipeline capacity on either EIPLP or other competitor pipelines can make transportation of crude oil by rail competitive, particularly to markets not currently serviced by pipelines. The Manager believes the liquids pipelines continue to provide attractive options to producers in the WCSB due to its competitive tolls and flexibility through its multiple delivery and storage points. Enbridge’s current complement of growth projects, including those in execution by EIPLP, to expand market access and to enhance capacity on EIPLP’s pipeline system combined with the Manager’s commitment to project execution is expected to further provide shippers reliable and long-term competitive solutions for oil transportation. EIPLP’s existing right-of-way for the Canadian Mainline also provides a competitive advantage as it can be difficult and costly to obtain rights of way for new pipelines traversing new areas. EIPLP also employs long-term agreements with shippers, which also mitigate competition risk by ensuring consistent supply to its liquids pipelines network.

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Foreign Exchange and Interest Rate Risk The CTS agreement for the Canadian Mainline exposes EIPLP to risks related to movements in foreign exchange rates and interest rates. Foreign exchange risk arises as the IJT under the CTS is charged in United States dollars. These risks have been substantially managed through the Manager’s enterprise-wide hedging program by using financial contracts to fix the prices of United States dollars and interest rates. Certain of these financial contracts do not qualify for cash flow hedge accounting and therefore, EIPLP’s earnings are exposed to associated changes in the mark-to-market value of these contracts. GAS PIPELINES EARNINGS BEFORE INTEREST AND INCOME TAXES 2015 2014 2013 (millions of Canadian dollars) Gas Pipelines 151 74 57 Adjusted earnings before interest and income taxes 151 74 57 Retrospective adjustment - 2014 Transaction1 - 64 62 Gas Pipelines - changes in unrealized derivative fair value loss (15) (6) - Gas Pipelines - derecognition of regulatory balances 8 - - Gas Pipelines - unrecoverable regulatory costs - - (2) Earnings before interest and income taxes 144 132 117 1 In accordance with U.S. GAAP, EBIT have been retrospectively adjusted to reflect the 2014 Transaction prior to the effective

date of the transaction. The impact of the retrospective adjustments has been removed from adjusted EBIT to reflect earnings generated under EIPLP’s ownership prior to November 7, 2014.

Additional details on items impacting Gas Pipelines EBIT include:

• Earnings from Alliance Pipeline US for the years ended December 31, 2015 and 2014 reflected changes in unrealized losses on derivative financial instruments used to manage foreign exchange exposures associated with United States dollar denominated distributions from Alliance Pipeline US.

• EIPLP’s equity pick-up of Alliance Pipeline was impacted by the derecognition of regulatory liabilities within those entities in the second quarter of 2015.

ALLIANCE PIPELINE SYSTEM Gas Pipelines consists of Alliance Pipeline, a 3,000-kilometre natural gas mainline pipeline, which includes the Canadian and United States portions of the pipeline and approximately 860 kilometres of lateral pipelines and related infrastructure. The Alliance Pipeline Canada portion begins near Aiken Creek, British Columbia and connects to Alliance Pipeline US at the Canada/United States border near Elmore, Saskatchewan. The Alliance Pipeline US portion continues to the Aux Sable gas processing plant near Chicago, Illinois and the Alliance Chicago gas exchange hub. Alliance Pipeline Canada and Alliance Pipeline US have annual firm transportation service shipping contract capacity of 1,325 million cubic feet per day and 1,455 million cubic feet per day, respectively. In September 2013, Alliance Pipeline US completed construction of the Tioga Lateral which facilitates delivery of natural gas from the Tioga field processing plant in the Bakken to downstream markets. Indirect wholly-owned subsidiaries of EIPLP acquired a 50% interest in Alliance Pipeline US from indirect wholly-owned subsidiaries of Enbridge on November 7, 2014. Refer to Overview – The 2014 Transaction. Prior to December 1, 2015, Alliance Pipeline Canada had transportation service agreements (TSA) with shippers for substantially all of its available firm transportation capacity. The TSA were designed to provide toll revenues sufficient to recover prudently incurred costs of service, including operating and maintenance, depreciation, an allowance for income tax, costs of indebtedness and an allowed ROE of 11.26% after-tax, based on a deemed 70/30 debt/equity ratio. Alliance Pipeline US had similar TSA which allowed for the recovery of the cost of service, which includes operating and maintenance costs, the cost of financing, an allowance for income tax, an annual allowance for depreciation and an allowed ROE of 10.88%. In addition, Alliance Pipeline US negotiated non-renewal charges that are an exit fee for shippers that did not elect to extend their transportation contracts. The initial term of the TSA expired in December

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2015, with the exception of a small proportion of shippers that have elected to extend their contracts beyond 2015. Alliance Pipeline Recontracting In 2013, Alliance Pipeline announced a new services framework and the related tolls and tariff provisions required to implement the new services (collectively, New Services Framework). On June 30, 2015 and July 9, 2015, Alliance Pipeline received regulatory approval from the Federal Energy Regulatory Commission (FERC) and the NEB, for the United States and Canadian segments of the pipeline, respectively, for the New Services Framework. Shipments under the New Services Framework commenced December 1, 2015. As part of its acceptance of Alliance Pipeline US’ New Services Framework, the FERC set all issues related to the proposed elimination of Authorized Overrun Service and Interruptible Transportation revenue crediting, and the maintenance of Alliance Pipeline US’ existing recourse rates, for hearing. The negotiated reservation rates contained in the Precedent Agreements were converted into negotiated rate transportation contracts as part of the New Services Framework and will not be part of this hearing. As part of the Canadian portion of the New Services Framework, the NEB granted pricing discretion for interruptible transportation and seasonal firm service with all associated revenues accruing to Alliance Pipeline Canada. Alliance Pipeline has successfully recontracted its annual firm service capacity with an average contract length of approximately five years. Pursuant to the New Services Framework, Alliance Pipeline retains exposure to potential variability in certain future costs and market based revenues generated from services provided beyond annual firm transport service. As such, the majority of Alliance Pipeline’s operations no longer meet all of the criteria required for the continued application of rate-regulated accounting treatment and derecognition of regulatory balances as at June 30, 2015 was required. As a result, EIPLP’s equity pick-up of Alliance Pipeline, recorded in the Gas Pipelines segment, included a one-time, non-cash pre-tax gain of $8 million due to the derecognition of regulatory liabilities within Alliance Pipeline. Further, EIPLP recorded a one-time, non-cash loss of $16 million related to a regulatory asset EIPLP recorded in respect of Alliance Pipeline Canada deferred tax within Eliminations and Other. Results of Operations Gas Pipelines adjusted EBIT for the year ended December 31, 2015 increased compared with the same period of 2014 primarily due to incremental contributions from Alliance Pipeline US as a result of the 2014 Transaction, partially offset by a shutdown of Alliance Pipeline Canada in August 2015. The Alliance Pipeline Canada portion was shut down on August 7, 2015 as hydrogen sulphide entered into its mainline pipeline system as a result of complications experienced by an upstream operator. Alliance Pipeline Canada returned to service on August 13, 2015 after flaring operations reduced the amount of hydrogen sulphide to a safe level. Additionally, contributing to the positive year over year increase were higher revenues in December 2015 resulting from the recontracting under the New Services Framework. The increase in adjusted EBIT for the year ended December 31, 2014 compared with the year ended December 31, 2013 was primarily driven by the addition of earnings from Alliance Pipeline US in the fourth quarter of 2014 subsequent to the 2014 Transaction. Throughput Volume 2015 2014 2013 (millions of cubic feet per day) Average throughput volume Alliance Pipeline Canada 1,488 1,556 1,565 Alliance Pipeline US 1,645 1,682 1,652 Alliance Pipeline throughput volume for the year ended December 31, 2015 decreased compared with the corresponding 2014 and 2013 periods. The decrease was attributable to the shut-down of the Alliance Pipeline Canada on August 7, 2015, as noted above.

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Business Risks The risks identified below are specific to Gas Pipelines. General risks that affect EIPLP as a whole are described under Risk Management and Financial Instruments – General Business Risks. Asset Utilization Currently, natural gas pipeline capacity out of the WCSB exceeds supply. Alliance Pipeline to date has been relatively unaffected by the excess supply environment as the Alliance Pipeline was successfully recontracted. Further, Alliance Pipeline is well positioned to deliver incremental liquids-rich gas production from developments in the Montney, Duvernay and Bakken regions large natural gas markets and following extraction and fractionation at the Aux Sable NGL extraction and fractionation plant, to deliver NGL to growing markets. As noted above, Alliance Pipeline’s New Services Framework also allows for the provision of services beyond annual firm transport service, at market rates, further supporting asset utilization. Competition Alliance Pipeline faces competition for pipeline transportation services to the Chicago, Illinois area from both existing pipelines and proposed pipeline projects from existing and new gas developments throughout North America. Any new or upgraded pipelines could either allow shippers greater access to natural gas markets or offer natural gas transportation services that are more desirable than those provided by the Alliance Pipeline because of location, facilities or other factors. In addition, any new, existing or upgraded pipelines could charge tolls or rates or provide transportation services to locations that result in greater net profit for shippers, with the effect of reducing future supply for the Alliance Pipeline. The ability of the Alliance Pipeline to cost-effectively transport liquids-rich gas and its proximity to the liquids-rich Montney, Duvernay and Bakken plays serve to enhance its competitive position. Economic Regulation Alliance Pipeline is subject to regulation by the NEB in Canada and the FERC in the United States. Under the New Services Framework effective December 1, 2015, Alliance Pipeline has contracted with shippers for tolls related to new services as approved by the NEB in Canada and the FERC in the United States. Firm service tolls are fixed for the duration of the contracts. GREEN POWER EARNINGS BEFORE INTEREST AND INCOME TAXES 2015 2014 2013 (millions of Canadian dollars) Green Power 112 93 93 Adjusted earnings before interest and income taxes 112 93 93

Retrospective adjustment - 2015 Transaction1 36 37 (60) Green Power - changes in unrealized derivative fair value gains 3 - - Green Power - transformer outage costs, net of recoveries 3 (3) -

Earnings before interest and income taxes 154 127 33 1 In accordance with U.S. GAAP, EBIT have been retrospectively adjusted to reflect the 2015 Transaction prior to the effective

date of the transaction. The impact of the retrospective adjustments has been removed from adjusted EBIT to reflect earnings generated under EIPLP’s ownership prior to September 1, 2015.

Green Power includes 1,052 MW of net renewable and alternative energy sources. Of this amount, approximately 930 MW of net power generating capacity comes from three wind farms located in each of Alberta, Ontario and Quebec. Most of the power produced from these wind farms are sold under long-term PPA. Also included in Green Power are three solar facilities located in Ontario with 100 MW of net power generating capacity. EIPLP also has a 50% interest in NRGreen Power Limited Partnership (NRGreen). NRGreen operates five waste heat recovery facilities with an aggregate capacity of 34 MW (17 MW net), which are located at compressor stations along the Alliance Pipeline in Alberta and Saskatchewan. Power is generated by harnessing the waste heat produced by gas turbines at Alliance Pipeline Canada’s compressor stations and converting the waste heat to electrical energy.

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RESULTS OF OPERATIONS Green Power adjusted EBIT for the year ended December 31, 2015 increased compared with the year ended December 31, 2014. Following the close of the 2015 Transaction, Green Power results included earnings from the Lac Alfred, Massif du Sud, Blackspring Ridge and Saint Robert Bellarmin wind projects. Period-over-period, there were offsetting results from EIPLP’s legacy assets. Adjusted EBIT increased slightly at Greenwich Wind and Sarnia Solar facilities due to higher wind resources and stronger irradiance, respectively, offset by a small decrease in adjusted EBIT from Talbot Wind Facility due to lower wind resources and outages at facilities affecting NRGreen. Green Power adjusted EBIT for the year ended December 31, 2014 was comparable with the corresponding 2013 period. Weaker wind resources at Ontario and Talbot wind facilities were offset by stronger performance from the Sarnia and Amherstburg solar facilities. BUSINESS RISKS The risks identified below are specific to Green Power. General risks that affect EIPLP as a whole are described under Risk Management and Financial Instruments – General Business Risks. Asset Utilization Earnings from EIPLP’s wind and solar assets are highly dependent on weather and atmospheric conditions as well as continued operational availability of these energy producing assets. While the expected energy yields for the Green Power assets are predicted using long-term historical data, wind and solar resources will be subject to natural variation from year to year and from season to season. Any prolonged reduction in wind or solar resources at any of EIPLP’s facilities could lead to decreased earnings for EIPLP. Additionally, inefficiencies or interruptions of EIPLP’s facilities due to operational disturbances or outages could also impact earnings. EIPLP mitigates the risk of operational availability by establishing Operations and Maintenance contracts with the original equipment manufacturers that include a negotiated operational performance asset guarantee and monitoring the operational reliability of the assets on a 24-hour basis. Power produced from Green Power assets is also often sold to a single counterparty under PPA or other long-term pricing arrangements. In this respect, the performance of the Green Power assets is dependent on each counterparty performing its contractual obligations under the PPA or pricing arrangement applicable to it. Competition Green Power assets operate in the Canadian power market, which is subject to competition and the supply and demand balance for power in the provinces in which they operate. The renewable energy market sector includes large utilities and small independent power producers, which are expected to aggressively compete with the Manager for project development opportunities. Regulatory Specific to EIPLP’s wind farms located in the province of Ontario, renewable generators are classified as intermittent generators under the Independent Electricity System Operator (IESO) Market Rules. Amendments to the IESO Market Rules were passed on November 29, 2012, to allow for curtailment of intermittent generators in times of surplus base-load generation. EIPLP and other renewable power generators reached an agreement with the IESO in February 2013 to amend certain existing PPA to include both annual and contract term curtailment caps beyond which renewable power generators will be compensated for forgone production. Uncompensated curtailment impacts less than 1% of the operating hours of the Ontario wind farms and is expected to remain consistent over the life of the PPA.

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Transmission Systems The ability of Green Power assets to deliver power is impacted by the availability of, and access to, interconnection facilities and transmission systems. The inability to access or unavailability of such systems, the operational failure of such systems or the lack of adequate capacity on them could have a material adverse impact on EIPLP’s ability to deliver power to counterparties or the requirement of counterparties to pay for energy delivery under various contracts, which in turn could have a material adverse effect on EIPLP’s cash flow or financial condition. LIQUIDITY AND CAPITAL RESOURCES SOURCES AND USES OF CASH EIPLP’s primary uses of cash are distributions to its partners, administrative and operational expenses, maintenance and enhancement capital spending as well as interest and principal repayments on its long-term debt. EIPLP generates cash from operations, commercial paper issuances and credit facility draws, through the periodic issuance of public term debt and issuance of units to its partners. Additionally, to ensure ongoing liquidity and to mitigate the risk of capital market disruption, EIPLP maintains a level of committed bank credit facilities. In addition to ensuring adequate liquidity, EIPLP actively manages its bank funding sources to optimize pricing and other terms. Additional liquidity, if necessary, is expected to be available through intercompany transactions with Enbridge or other related entities. Long-term Debt Long-term debt consists of committed credit facilities through EPI and medium-term notes issued by EPI. As at December 31, 2015, EIPLP had $3,005 million of committed credit facilities of which $1,346 million were drawn or allocated to backstop commercial paper. EPI must adhere to covenants under its credit facility agreement and Trust Indenture. Under terms of EPI’s Trust Indenture, in order to continue to issue long-term debt, EPI must maintain a ratio of Consolidated Funded Obligations to Total Consolidated Capitalization of less than 75%. Total Consolidated Capitalization consists of shareholder’s equity, long-term debt and deferred income taxes. As at December 31, 2015, EPI was in compliance with all debt covenants. During the year ended December 31, 2015, unsecured medium-term notes of $600 million with a 10-year maturity and $400 million with a 30-year maturity were issued through EPI. Equity On September 1, 2015, EIPLP issued Class A units to ECT for gross proceeds of approximately $3,000 million. The aggregate proceeds from this issuance were used to satisfy the cash portion of the purchase price payable to Enbridge and certain of its subsidiaries related to the 2015 Transaction. EIPLP also issued Class C units, one Class E unit and SIR as non-cash consideration to partially fund the 2015 Transaction. For further details, refer to Canadian Restructuring Plan. On November 6, 2015, EIPLP issued Class A units to ECT for gross proceeds of approximately $874 million. The aggregate proceeds from this issuance were used to fund EIPLP’s secured capital growth programs.

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Distributions The following tables summarize the cash and non-cash distributions declared by EIPLP for the years ended December 31, 2015, 2014 and 2013, and for the quarters therein, as applicable. Class A Units 2015 2014 2013

Distribution

Rate1 Total Distribution

Rate1 Total Distribution

Rate1 Total (millions of Canadian dollars, except distribution rate) Three months ended March 31, 0.4938 121 0.4299 81 0.3650 69 Three months ended June 30, 0.4938 121 0.4299 81 0.4060 76 Three months ended September 30, 0.4919 135 0.4299 81 0.4265 80 Three months ended December 31, 0.4874 169 0.4724 106 0.4276 80 Year ended December 31, 1.9669 546 1.7621 349 1.6251 305 1 Class A unit distributions are declared monthly and paid in cash in the following month. Class C Units 2015

Distribution

Rate1 Total (millions of Canadian dollars, except distribution rate) Three months ended September 30, 0.1574 70 Three months ended December 31, 0.4723 209 Year ended December 31, 0.6297 279 1 Class C unit distributions are declared monthly and paid in cash in the following month. Class C units were first issued on

September 1, 2015 pursuant to the 2015 Transaction. Class D Units 2015

Distribution

Rate1 Total (millions of Canadian dollars, except distribution rate) Three months ended December 31, 0.4723 1 Year ended December 31, 0.4723 1 1 Class D unit distributions are declared monthly and paid-in-kind with the issuance of additional Class D units in the following

month. Class D units were first issued in October 2015 pursuant to the first payment of TPDR distributions of the SIR. Special Interest Rights – TPDR 2015 Total (millions of Canadian dollars) Three months ended September 30, 14 Three months ended December 31, 44 Year ended December 31, 58 1 TPDR distributions are declared monthly and paid-in-kind with the issuance of additional Class D units in the following month.

SIR were first issued on September 1, 2015 pursuant to the 2015 Transaction. Capital Expenditures A summary of additions to property, plant and equipment is as follows: Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Liquids Pipelines 3,064 4,152 2,877 Green Power 4 204 308 Total capital expenditures 3,068 4,356 3,185

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AVAILABLE LIQUIDITY EIPLP’s net available liquidity of $1,755 million as at December 31, 2015 was inclusive of $129 million of unrestricted cash and cash equivalents and net of bank indebtedness of $33 million. The net available liquidity, together with cash from operations, intercompany funding and proceeds of debt capital market transactions, is expected to be sufficient to finance capital expenditures requirements, fund liabilities as they become due, fund debt retirements and pay distributions. Excluding current maturities of long-term debt, as at December 31, 2015 and 2014, EIPLP had negative working capital positions of $1,120 million and $8,978 million, respectively, which contemplates the realization of assets and the liquidation of liabilities. Despite this negative working capital, EIPLP has significant net available liquidity through committed credit facilities and other sources as previously discussed, which allow the funding of liabilities as they become due. In addition, it is anticipated that any current maturities of long-term debt will be refinanced upon maturity. December 31, 2015 2014 (millions of Canadian dollars) Cash and cash equivalents 129 162 Accounts receivable and other1 662 528 Loans to affiliates 3 3 Bank indebtedness (33) (35) Short-term borrowings - (103) Accounts payable and other2 (1,598) (1,089) Distribution payable to affiliate (143) (40) Interest payable (45) (37) Loans from affiliates (95) (8,367) Working capital (1,120) (8,978) 1 Includes Accounts receivable from affiliates. 2 Includes Accounts payable to affiliates. CONTRACTUAL OBLIGATIONS Payments due under contractual obligations over the next five years and thereafter are as follows:

Total Less than

1 year 1-3 years 3-5 years After 5 years

(millions of Canadian dollars) Long-term debt1 4,261 14 334 682 3,231 Loans from affiliates 5,896 95 - 600 5,201 Capital and operating leases 149 11 20 15 103 Long-term contracts 2,372 1,502 481 71 318 Total contractual obligations 12,678 1,622 835 1,368 8,853 1 Represents debenture and term note maturities and excludes interest obligations. Changes to the planned funding

requirements are dependent on the terms of any debt refinancing agreements. CAPITAL EXPENDITURE COMMITMENTS Included within Long-term contracts in the table above are contracts that EIPLP has signed primarily for the purchase of services, pipe and other materials totalling $1,812 million, which are expected to be paid over the next five years. OTHER LITIGATION EIPLP and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, the Manager believes that the resolution of such actions and proceedings will not have a material impact on EIPLP’s consolidated financial position or results of operations.

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QUARTERLY FINANCIAL INFORMATION1,2

2015 Q1 Q2 Q3 Q4 Total (millions of Canadian dollars) Revenues (60) 1,007 180 747 1,874 Earnings/(loss) attributable to general and limited

partners (301) 469 (274) 228 122 2014 Q1 Q2 Q3 Q4 Total (millions of Canadian dollars) Revenues 440 980 358 408 2,186 Earnings attributable to general and limited partners 106 466 14 45 631 1 Quarterly financial information has been retrospectively adjusted to reflect the 2015 Transaction and the 2014 Transaction in

information prior to the respective effective dates of the transactions as prescribed by U.S. GAAP for common control transactions.

2 Revenues and Earnings/(loss) attributable to general and limited partners are impacted by changes in unrealized derivative fair value gains and losses on derivatives.

Several factors impact comparability of EIPLP’s financial results on a quarterly basis, including, but not limited to, fluctuations in market prices such as foreign exchange rates and commodity prices, disposals of investments or assets and the timing of in-service dates of new projects. EIPLP actively manages its exposure to market risks including, but not limited to, interest rates, commodity prices and foreign exchange rates. To the extent derivative instruments used to manage these risks are non-qualifying for the purposes of applying hedge accounting, changes in unrealized fair value gains and losses on these instruments will impact earnings. EIPLP’s Green Power segment is subject to seasonal variations. This is driven by stronger wind resources in the first and fourth quarters and stronger solar resources in the second and third quarters. Although these trends are offsetting, revenues and earnings are generally expected to be lowest in the third quarter, attributable to seasonally weaker wind resources. As part of the 2015 Transaction, the commercially secured growth programs embedded within EPI and EPAI were transferred to EIPLP. Prior to the close of the 2015 Transaction, both EPI and EPAI undertook a substantial capital growth over the past recent years. The timing of construction and completion of growth projects may impact the comparability of EIPLP’s quarterly results. EIPLP’s capital expansion initiatives, including construction commencement and in-service dates, are described in Growth Projects. RELATED PARTY TRANSACTIONS All related party transactions are entered into in the normal course of business and, unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. Affiliates refer to Enbridge and companies that are either directly or indirectly owned by Enbridge. The acquisition of the Purchased Entities and equity investment in Alliance Pipeline US were accounted for as transactions among entities under common control. GENERAL PARTNER Enbridge Income Partners GP Inc. (EIPGP), a subsidiary of Enbridge, is the general partner of EIPLP and has a 0.01% interest in the Class A units of EIPLP. As at December 31, 2015, Enbridge holds a 51% direct interest in EIPGP. Per EIPLP’s partnership agreement, EIPGP has the right to manage, control and operate the businesses of EIPLP. EIPGP delegates the execution of certain of its powers to EMSI, a wholly-owned subsidiary of Enbridge, who administers EIPLP.

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INTERCORPORATE SERVICES On August 2, 2015 all Canadian employees of EPI and EPAI were transferred to an affiliated company which assumed all employment related obligations, commitments and liabilities. The related net pension and other postemployment benefit liabilities, as well as the related unamortized losses recorded in Accumulated other comprehensive income (AOCI), were not included in the retrospective consolidated financial statements as EIPLP has elected to recognize required contributions for the period as net pension costs without reflecting related plan benefit obligations and plan assets. Pension related costs of $45 million for the year ended December 31, 2015 (2014 - $48 million; 2013 - $51 million) were recorded in Operating and administrative expense on the Consolidated Statements of Earnings. As at December 31, 2015, EIPLP and its subsidiaries do not have any employees and receives services from affiliates for managing and operating the business. These services, which are charged at cost in accordance with service agreements or which reflect normal commercial trade terms, totalled $234 million for the year ended December 31, 2015 (2014 - $90 million; 2013 - $82 million). EIPLP provides certain operational services to affiliates. These services, which are charged at cost in accordance with service agreements or which reflect normal commercial trade terms, totalled $166 million for the year ended December 31, 2015 (2014 - $214 million; 2013 - $177 million). LIQUIDS PIPELINES EIPLP has contracts with shippers who are also affiliates of EIPLP through common ownership interests of Enbridge. Revenues from affiliates, which reflect normal commercial trade terms, totalled $78 million for the year ended December 31, 2015 (2014 - $51 million; 2013 - $71 million). GAS PIPELINES Alliance Pipeline has contracts with shippers that are also affiliates of EIPLP through common ownership interests of Enbridge. EIPLP’s share of Alliance Pipeline’s revenues from affiliates for the year ended December 31, 2015 was $59 million (2014 - $50 million; 2013 - $50 million). LONG-TERM RECEIVABLE FROM AFFILIATE Long-term receivable from affiliate includes the carrying value of Class A Units of Southern Lights Holdings, L.L.C., which is an indirect wholly-owned subsidiary of Enbridge. As at December 31, 2015, $826 million (2014 - $707 million) is included in Long-term receivable from affiliate and $18 million (2014 - $12 million) is included in Accounts receivable from affiliates. Interest income of $61 million for the year ended December 31, 2015 (2014 - $5 million; 2013 - nil), has been recorded within Other income - affiliates on the Consolidated Statements of Earnings. INVESTMENT IN AFFILIATED COMPANY As at December 31, 2015, EIPLP had an investment of $514 million in 500,000 non-voting, redeemable Series A Preferred Shares of EESCI. These Preferred Shares entitle EIPLP to receive annual dividends through 2021. EESCI has the option to redeem the outstanding Preferred Shares at any time. EIPLP is also entitled to require redemption of these Preferred Shares at any time. Dividend income of $14 million was recognized in Other income - affiliates for the year ended December 31, 2015 (2014 - nil; 2013 - nil). During the year ended December 31, 2015, a subsidiary of Enbridge exercised its option to redeem the $160 million in 160,000 non-voting, redeemable preference shares that were held as an investment by EPAI, a subsidiary of EIPLP. The investment was acquired in 2014 and entitled EPAI to receive a minimum cumulative quarterly dividend equal to 106.25% of the cost of funds incurred by EPAI to finance its acquisition of these preference shares. Dividend income of $4 million was recognized in Other income - affiliates for the year ended December 31, 2015 (2014 - $12 million; 2013 - nil).

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During the year ended December 31, 2014, Enbridge Energy Distribution Inc. (EEDI) exercised its option to redeem the $2,690 million in 2.69 million non-voting, redeemable, retractable preference shares of EEDI that were held as an investment by EPI, a subsidiary of EIPLP. The investment was acquired in 2013 and entitled EPI to receive a cumulative quarterly dividend equal to 106.25% of the cost of funds incurred by EPI to finance its acquisition of these preference shares. INTERCORPORATE LOANS AND BALANCES Loans to Affiliates The following loans to affiliates are evidenced by formal loan agreements. Interest rates for short-term loans are based on the applicable short-term LIBOR for the United States dollar loans and Canadian Depository Offering Rate for the Canadian dollar loans. 2015 2014

December 31, Maturity

Weighted Average Interest

Rate Amount

Weighted Average Interest

Rate Amount (millions of Canadian dollars) Affiliate Current 6.0% 3 - - Affiliate - - - 12.0% 3 Enbridge - - - 7.9% 325

3 328 Current portion of loans to affiliates (3) (3) - 325 Loans from Affiliates The following loans from affiliates are evidenced by formal loan agreements: 2015 2014

December 31,

Maturity

Weighted Average Interest

Rate

Amount

Weighted Average Interest

Rate

Amount (millions of Canadian dollars) Enbridge 2020-2064 4.6% 4,191 - - Enbridge 2025 4.0% 124 - - Affiliate Current 1.9% 47 2.4% 216 Affiliate Current 4.3% 48 4.3% 31 Affiliate 2020 7.1% 100 7.1% 100 Affiliate 2045 4.0% 734 - - Affiliate 2045 4.0% 652 - - Enbridge - - - 3.3% 3,463 Enbridge - - - 4.8% 3,307 Enbridge - - - 7.2% 160 Affiliate - - - 1.6% 634 Affiliate - - - 1.5% 487 Affiliate - - - 3.5% 229 5,896 8,627 Current portion of loans from affiliates (95) (8,367)

5,801 260 Loans from affiliates’ maturities for the year ending December 31, 2016 are $95 million, nil for each of the years ending December 31, 2017 through 2019 and $600 million for the year ending December 31, 2020. These loans are subordinate to senior, unsecured debt. The affiliate loan interest obligations for the year ending December 31, 2016 are $273 million, $260 million for each of the years ending December 31, 2017 through 2019 and $240 million for the year ending December 31, 2020.

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As at December 31, 2015, EIPLP had a net hedge payable balance of $2,501 million (2014 - $1,023 million net payable) to affiliates in respect of derivative instruments that the affiliates entered into on EIPLP’s behalf. These amounts are recorded in Accounts receivable from affiliates, Deferred amounts and other assets, Accounts payable to affiliates and Other long-term liabilities on the Consolidated Statements of Financial Position. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Maintaining a reliable and low risk business model is central to the EIPLP’s objective of paying out a predictable cash flow to partners. The Fund Group actively manages both financial and non-financial risks EIPLP is exposed to. The Fund Group performs an annual corporate risk assessment to identify all potential risks. Risks are ranked based on severity and likelihood both before and after mitigating actions. In addition, the Fund Group has adopted a Cash Flow at Risk (CFAR) policy to manage exposure to movements in interest rates, foreign exchange rates and commodity prices. CFAR is a statistically derived measurement that quantifies the maximum adverse impact on cash flows over a specified period of time within a pre-defined level of statistical confidence. The Fund Group’s CFAR limit has been set at 2.5% of forward annual ACFFO of the Fund Group. MARKET PRICE RISK EIPLP’s earnings, cash flows and OCI are subject to movements in interest rates, foreign exchange rates and commodity prices (collectively, market price risk). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market price risks to which EIPLP is exposed and the risk management instruments used to mitigate them. EIPLP uses a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Interest Rate Risk EIPLP’s earnings, cash flows and OCI are exposed to short term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are used to hedge against the effect of future interest rate movements. EIPLP has implemented a program to significantly mitigate the volatility of short-term interest rates on interest expense through 2019 with the execution of floating to fixed rate interest rate swaps with an average swap rate of 1.4%. EIPLP’s earnings, cash flows and OCI are also exposed to variability in longer term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. EIPLP has implemented a program to significantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances through 2019 with the execution of floating to fixed rate interest rate swaps with an average swap rate of 3.1%. EIPLP’s portfolio mix of fixed and variable rate debt instruments is managed at the Fund Group level. Foreign Exchange Risk EIPLP generates certain revenues, incurs expenses and holds investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, EIPLP’s earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. EIPLP has implemented a policy whereby, at a minimum, it hedges a level of foreign currency denominated cash flow exposures over a five year forecast horizon. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows.

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Commodity Price Risk EIPLP’s earnings, cash flows and OCI are exposed to changes in commodity prices as a result of its ownership interest in certain assets and investments. These commodities primarily consist of crude oil and power. EIPLP employs financial derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. EIPLP may use a combination of qualifying and non-qualifying derivative instruments to manage commodity price risk. The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income The following table presents the effect of cash flow hedges on EIPLP’s consolidated earnings and consolidated comprehensive income, before the effect of income taxes. Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Amount of unrealized gains/(loss) recognized in OCI

Cash flow hedges Foreign exchange contracts 2 1 1 Interest rate contracts (38) (174) 32 Commodity contracts 6 11 3

(30) (162) 36 Amount of gains/(loss) reclassified from AOCI to earnings (effective portion)

Foreign exchange contracts1 - (1) - Interest rate contracts2 9 3 45 Commodity contracts3 (7) (2) 1

2 - 46 Amount of loss reclassified from AOCI to earnings (ineffective portion and

amount excluded from effectiveness testing) Interest rate contracts2 - (1) (2)

- (1) (2) Amount of gains/(loss) from non-qualifying derivatives included in earnings

Foreign exchange contracts1 (1,487) (522) (353) Commodity contracts3 (8) 3 (91)

(1,495) (519) (444) 1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of

Earnings. 2 Reported as an increase/(decrease) within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Electricity sales revenues and Other income/(expense) in the Consolidated Statements of Earnings. LIQUIDITY RISK Liquidity risk is the risk EIPLP will not be able to meet its financial obligations, including commitments and guarantees, as they become due. In order to manage this risk, EIPLP forecasts cash requirements over the near and long term to determine whether sufficient funds will be available when required. EIPLP generates cash from operations, commercial paper issuances and credit facility draws, through the periodic issuance of public term debt and issuance of units to its partners. Additionally, to ensure ongoing liquidity and to mitigate the risk of market disruption, EIPLP maintains a level of committed bank credit facilities. In addition, to ensure adequate liquidity, EIPLP actively manages its bank funding sources to optimize pricing and other terms. Additional liquidity, if necessary, is expected to be available through intercompany transactions with Enbridge or other related entities. EIPLP is in compliance with all terms and conditions of its committed credit facilities as at December 31, 2015. As a result, all credit facilities are available to EIPLP and the banks are obliged to fund and have been funding EIPLP under the terms of the credit facilities.

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CREDIT RISK Entering into derivative financial instruments may result in exposure to credit risk. Credit risk arises from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, EIPLP enters into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, frequent assessment of counterparty credit ratings and netting arrangements. EIPLP generally has a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of its derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce EIPLP’s credit risk exposure on derivative asset positions outstanding with the counterparties in these particular circumstances. Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits, contractual requirements, assessment of credit ratings and netting arrangements. Generally, EIPLP classifies and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value. FAIR VALUE MEASUREMENTS EIPLP’s financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. EIPLP also discloses the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects EIPLP’s best estimates of market value based on generally accepted valuation techniques or models and are supported by observable market prices and rates. When such values are not available, EIPLP uses discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value. GENERAL BUSINESS RISKS Strategic and Commercial Risks Public Opinion Public opinion or reputation risk is the risk of negative impacts on EIPLP’s business, operations or financial condition resulting from changes in Enbridge’s enterprise-wide reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion may be influenced by certain media and special interest groups’ negative portrayal of the industry in which EIPLP operates as well as their opposition to development projects. Potential impacts of a negative public opinion may include loss of business, delays in project execution, legal action, increased regulatory oversight or delays in regulatory approval and higher costs. Reputation risk often arises as a consequence of some other risk event, such as in connection with operational, regulatory or legal risks. Therefore, reputation risk cannot be managed in isolation from other risks. Enbridge manages enterprise-wide reputation risk by:

• having health, safety and environment management systems in place, as well as policies, programs and practices for conducting safe and environmentally sound operations with an emphasis on the prevention of any incidents;

• having formal risk management policies, procedures and systems in place to identify, assess and mitigate risks;

• operating to the highest ethical standards, with integrity, honesty and transparency, and maintaining positive relationships with customers, investors, employees, partners, regulators and other stakeholders;

• building awareness and understanding of the role energy and Enbridge play in people’s lives in order to promote better understanding of Enbridge and its businesses;

• having strong corporate governance practices, including a Statement on Business Conduct, which requires all employees to certify their compliance with Enbridge policy on an annual basis, and whistleblower procedures, which allow employees to report suspected ethical concerns on a confidential and anonymous basis; and

• pursuing socially responsible operations as a longer-term corporate strategy.

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Enbridge’s actions noted above are the key mitigation actions against negative public opinion; however, the public opinion risk cannot be mitigated solely by Enbridge’s individual actions. Enbridge actively works with other stakeholders in the industry to collaborate and work closely with government and Aboriginal communities to enhance the public opinion of Enbridge, as well as the industry in which it operates. Unless otherwise specifically stated, none of the content of the policies or initiatives described above are incorporated by reference herein. Project Execution As EIPLP’s slate of growth projects increases, it continues to focus on completing projects safely, on-time and on-budget. The ability to successfully execute the development of its organic growth projects may be influenced by capital constraints, third-party opposition, changes in shipper support over time, delays in or changes to government and regulatory approvals, cost escalations, construction delays, inadequate resources, in-service delays and increasing complexity of projects (collectively, Execution Risk). Early stage project risks include right-of-way procurement, special interest group opposition, Crown consultation and environmental and regulatory permitting. Cost escalations or missed in-service dates on future projects may impact future earnings and cash flows and may hinder the Manager’s ability to secure future projects. Construction delays due to regulatory delays, third-party opposition, contractor or supplier non-performance and weather conditions may impact project development. Enbridge, through its enterprise-wide Major Projects group, strives to be an industry leader in project execution. Major Projects seeks to mitigate project Execution Risk and is centralized and has a clearly defined governance structure and process for all major projects, with dedicated resources organized to lead and execute each major project. Capital constraints and cost escalation risks are mitigated through structuring of commercial agreements, typically where shippers retain complete or a share of capital cost excess. Detailed cost tracking and centralized purchasing is used on all major projects to facilitate optimum pricing and service terms. Strategic relationships have been developed with suppliers and contractors and those selected are chosen based on the Managers’ strict adherence to safety including robust safety standards embedded in contracts with suppliers. Major Projects has assessed work volumes for the next several years across its projects to optimize the expected costs, supply of services, material and labour to execute the projects. Underpinning this approach is Major Project’s Project Lifecycle Gating Control tool which helps to ensure schedule, cost, safety and quality objectives are on track and met for each stage of a project’s development and construction. Consultations with regulators are held in-advance of project construction to enhance understanding of project rationale and ensure applications are compliant and robust, while at all times maintaining a strong focus on integrity and public safety. Enbridge also actively involves its legal and regulatory teams to work closely with Major Projects to engage in open dialogue with government agencies, regulators, land owners, Aboriginal groups and special interest groups to identify and develop appropriate responses to their concerns regarding EIPLP’s projects. Operational and Economic Regulation, Permits and Approvals Many of EIPLP’s operations are regulated and are subject to both operational and economic regulatory risk. The nature and degree of regulation and legislation affecting energy companies in Canada and the United States has changed significantly in past years and there is no assurance that further substantial changes will not occur. Operational regulation risks relate to failing to comply with applicable operational rules and regulations from government organizations and could result in fines, operating restrictions or shutdown of assets or an overall increase in operating and compliance costs. Regulatory scrutiny over EIPLP’s assets has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on EIPLP’s future earnings and the cost related to the construction of new projects. The Manager believes operational regulation risk is mitigated by active monitoring and consulting on potential regulatory requirement changes with the respective regulators or through industry associations. EIPLP

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also develops robust response plans to regulatory changes or enforcement actions. While EIPLP believes the safe and reliable operation of its assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators to make unilateral decisions that could have a financial impact on EIPLP. EIPLP also faces economic regulation, permits and approvals risk, which broadly defined, is the risk that regulators or other government entities change or reject proposed or existing commercial arrangements including permits and regulatory approvals for new projects. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on EIPLP’s revenues, earnings and distributable cash flow. Increasing regulatory scrutiny and resulting delays in regulatory permits and approvals could result in cost escalations, constructions delays and in-service delays which also negatively impact EIPLP’s operations. The Manager believes that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers that govern the majority of its operations. The Manager also involves its legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations as well as in the establishment of tariffs and tolls for these assets. The Manager retains dedicated professional staff and maintains strong relationships with customers, intervenors and regulators to help minimize economic regulation risk. However, despite the efforts of the Manager to mitigate economic regulation risk, there remains a risk that a regulator could overturn long-term agreements between EIPLP and shippers or deny the approval and permits for new projects. EIPLP will be required to comply with numerous federal, provincial and local laws and regulations and to maintain and comply with numerous regulatory licenses, permits and governmental approvals required for the maintenance and operation of its assets. Many of the regulatory permits that have been issued in respect of EIPLP’s assets contain terms, conditions and restrictions, or may have limited terms. A failure to satisfy the terms and conditions or comply with the restrictions imposed under regulatory permits or the restrictions imposed by any statutory or regulatory requirements, may result in regulatory enforcement action, which could adversely affect continued operations, or result in fines, penalties or additional costs, including requirements to suspend or cease operations. Operational Risks Environmental Incident EIPLP is subject to the risk of incurring substantial costs and liabilities under environmental, health and safety laws applicable to its assets. Environmental and health and safety legislation imposes restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with noise, spills, releases and emissions of substances into the environment. Environmental Laws also mandate that pipelines, tanks, turbines, installations, facilities and other properties associated with its assets be operated, maintained, abandoned and reclaimed in accordance with applicable regulations and guidelines. Failure to comply with environmental, health and safety laws may result in the imposition of administrative and criminal penalties, civil liability, liens and the imposition of remedial obligations such as cleanup and site restoration requirements, the revocation or suspension of operating permits and the issuance of orders to limit or cease operations. An environmental incident could have lasting reputational impacts to EIPLP and could impact its ability to work with various stakeholders. In addition to the cost of remediation activities (to the extent not covered by insurance), environmental incidents may lead to an increased cost of operating and insuring EIPLP’s assets, thereby negatively impacting earnings and distributable cash flow. EIPLP mitigates risk of environmental incident through its inclusion in Enbridge’s ORM Plan, which broadly aims to position Enbridge and its subsidiaries as the industry leader for system integrity, environmental and safety programs. Mitigation efforts continue to focus on efforts to reduce the likelihood of an environmental incident. Under the umbrella of Enbridge’s ORM Plan, EIPLP has continued its maintenance, excavation and repair program which are supported by operating and capital budgets for pipeline integrity.

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Although the Manager believes its integrated management system, plans and processes mitigate the risk of environmental incidents, there remains a chance that an environmental incident could occur. The ORM Plan also seeks to mitigate the severity of a potential environmental incident through continued process improvements and enhancements in leak detection processes and alarm analysis procedures. The Manager has also invested significant resources to enhance its emergency response plans, operator training and landowner education programs to address any potential environmental incident. EIPLP is included in Enbridge’s comprehensive insurance policy, which covers Enbridge subsidiaries and affiliates and is renewed annually. The insurance program includes coverage for commercial liability that is considered customary for its industry and includes coverage for environmental incidents. The total insurance coverage will be allocated on an equitable basis in the unlikely event multiple insurable incidents exceeding Enbridge’s coverage limits are experienced by Enbridge and two Enbridge subsidiaries covered by the same policy within the same insurance period. Public, Worker and Contractor Safety Several of EIPLP’s pipeline systems run adjacent to populated areas and a major incident could result in injury to members of the public. A public safety incident could result in reputational damage to Enbridge and its subsidiaries, material repair costs or increased costs of operating and insuring its assets. In addition, given the natural hazards inherent with EIPLP’s operations, workers and contractors are subject to personal safety risks. Safety and operational reliability are the most important priorities. Mitigation efforts to reduce the likelihood and severity of a public safety incident are executed primarily through Enbridge’s ORM Plan and emergency response preparedness, as described above in Environmental Incident. Enbridge also actively engages stakeholders through public safety awareness activities to ensure the public is aware of potential hazards and understands the appropriate actions to take in the event of an emergency. Enbridge also actively engages first responders through education programs that endeavour to equip first responders with the skills and tools to safely and effectively respond to a potential incident. Information Technology Security or Systems Incident EIPLP’s infrastructure, applications and data are becoming more integrated, creating an increased risk that failure in one system could lead to a failure of another system. There is also increasing industry-wide cyber-attacking activity targeting industrial control systems and intellectual property. A successful cyber-attack could lead to unavailability, disruption or loss of key functionalities within EIPLP’s industrial control systems which could impact pipeline operations and potentially result in an environmental or public safety incident. A successful cyber-attack could also lead to a large scale data breach resulting in unauthorized disclosure, corruption or loss of sensitive information which could have lasting reputational impacts to EIPLP and could impact its ability to work with various stakeholders. The Manager has implemented a comprehensive security strategy that includes a security policy and standards framework, defined governance and oversight, layered access controls, continuous monitoring, infrastructure and network security and threat detection and incident response through a security operations centre. EIPLP’s information technology security operations are consolidated under one leadership structure to increase consistency and compliance with security requirements across business segments. Service Interruption Incident A service interruption due to a major power disruption or curtailment on commodity supply could have a significant impact on EIPLP’s ability to operate its assets and negatively impact future earnings, relationships with stakeholders and Enbridge’s enterprise-wide reputation. Service interruptions that impact EIPLP’s crude oil transportation services can negatively impact shippers’ operations and earnings as they are dependent on EIPLP services to move their product to market or fulfill their own contractual arrangements. EIPLP mitigates service interruption risk through its diversified sources of supply, storage withdrawal flexibility, backup power systems, critical parts inventory and redundancies for critical equipment.

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Business Environment Risks Aboriginal Relations Canadian judicial decisions have recognized that Aboriginal rights and treaty rights exist in proximity to EIPLP’s operations and future project developments. The courts have also confirmed that the Crown has a duty to consult with Aboriginal people when its decisions or actions may adversely affect Aboriginal rights and interests or treaty rights. Crown consultation has the potential to delay regulatory approval processes and construction, which may affect project economics. In some cases, respecting Aboriginal rights may mean regulatory approval is denied or the conditions in the approval make a project economically challenging. Given this environment and the breadth of relationships across EIPLP’s geographic span, Enbridge has implemented an enterprise-wide Aboriginal and Native American Policy. This policy promotes the achievement of participative and mutually beneficial relationships with Aboriginal and Native American groups affected by EIPLP’s projects and operations. Specifically, the policy sets out principles governing EIPLP’s relationships with Aboriginal and Native American people and makes commitments to work with Aboriginal people and Native Americans so they may realize benefits from EIPLP’s projects and operations. Notwithstanding EIPLP’s efforts to this end, the issues are complex and the impact of Aboriginal and Native American relations on operations and development initiatives is uncertain. Unless otherwise specifically stated, none of the content of this policy is incorporated by reference herein. Special Interest Groups including Non-Governmental Organizations The development and operation of EIPLP’s assets may at times be subject to public opposition which could expose EIPLP to the risk of higher costs, delays or even project cancellations due to increasing pressure on governments and regulators by special interest groups including aboriginal groups, landowners, environmental interest groups and other non-governmental organizations. Enbridge and its subsidiaries work proactively with special interest groups and non-governmental organizations to identify and develop appropriate responses to their concerns regarding its projects. CRITICAL ACCOUNTING ESTIMATES DEPRECIATION Depreciation of property, plant and equipment, EIPLP’s largest asset with a net book value at December 31, 2015 of $21,064 million (2014 - $18,856 million), or 82% of total assets, is generally provided on a straight-line basis over the estimated service lives of the assets commencing when the asset is placed in service. When it is determined that the estimated service life of an asset no longer reflects the expected remaining period of benefit, prospective changes are made to the estimated service life. Estimates of useful lives are based on third party engineering studies, experience and/or industry practice. There are a number of assumptions inherent in estimating the service lives of EIPLP’s assets including the level of development, exploration, drilling, reserves and production of crude oil and natural gas in the supply areas served by EIPLP’s pipelines as well as the demand for crude oil and natural gas and the integrity of EIPLP’s systems. Changes in these assumptions could result in adjustments to the estimated service lives, which could result in material changes to depreciation expense in future periods in any of EIPLP’s business segments. For certain rate-regulated operations, depreciation rates are approved by the regulator and the regulator may require periodic studies or technical updates on useful lives which may change depreciation rates. ASSET IMPAIRMENT EIPLP evaluates the recoverability of its property, plant and equipment when events or circumstances such as economic obsolescence, business climate, legal or regulatory changes, or other factors indicate it may not recover the carrying amount of the assets. EIPLP continually monitors its businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. An impairment loss is recognized when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires the use of projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes to these

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projections and assumptions could result in revisions to the evaluation of the recoverability of the property, plant and equipment and the recognition of an impairment loss in the Consolidated Statements of Earnings. EIPLP also tests goodwill for impairment annually or more frequently if events or changes in circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value. For the purposes of impairment testing, reporting units are identified as business operations within an operating segment. EIPLP has the option to first assess qualitative factors to determine whether it is necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test is performed, the first step involves determining the fair value of EIPLP’s reporting units inclusive of goodwill and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured as the excess of the carrying amount of the reporting unit’s allocated goodwill over the implied fair value of the goodwill based on the fair value of the reporting unit’s assets and liabilities. REGULATORY ASSETS AND LIABILITIES Certain of EIPLP’s businesses are subject to regulation by various authorities, including the NEB, the FERC, the Alberta Energy Regulator, Saskatchewan Ministry of Economy and Manitoba Mineral Resources. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non-rate-regulated entities. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the NEB’s Land Matters Consultation Initiative (LMCI). Long-term regulatory assets are recorded in Deferred amounts and other assets and current regulatory assets are recorded in Accounts receivable and other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts payable and other. Regulatory assets are assessed for impairment if EIPLP identifies an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from EIPLP’s expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, EIPLP would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. As at December 31, 2015, EIPLP’s net regulatory assets totalled $977 million (2014 - $919 million) after derecognition of the regulatory balances at Alliance Pipeline. Refer to Gas Pipelines – Alliance Pipeline System – Alliance Pipeline Recontracting. ASSET RETIREMENT OBLIGATIONS Asset retirement obligations (ARO) associated with the retirement of long-lived assets are measured at fair value and recognized as Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. EIPLP’s estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for certain of EIPLP’s assets, there is insufficient data or information to reasonably determine the timing of settlement for estimating the fair value of the ARO. In these cases, the ARO cost is considered indeterminate for accounting purposes, as there is no data or information that can be derived from past practice, industry practice or the estimated economic life of the asset.

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In 2009, the NEB issued a decision related to the LMCI, which required holders of an authorization to operate a pipeline under the NEB Act to file a proposed process and mechanism to set aside funds to pay for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline. The NEB’s decision stated that while pipeline companies are ultimately responsible for the full costs of abandoning pipelines, abandonment costs are a legitimate cost of providing service and are recoverable from the users of the pipeline upon approval by the NEB. Following the NEB’s final approval of the collection mechanism and the set-aside mechanism for LMCI, EIPLP began collecting and setting aside funds to cover future abandonment costs effective January 1, 2015. The funds collected are held in trust in accordance with the NEB decision. The funds collected from shippers are reported within Transportation and other services revenues and Restricted long-term investments. Concurrently, EIPLP reflects the future abandonment cost as an increase to Operating and administrative expense and Other long-term liabilities. CHANGES IN ACCOUNTING POLICIES ADOPTION OF NEW STANDARDS Extraordinary and Unusual Items Effective January 1, 2015, EIPLP retrospectively adopted Accounting Standards Update (ASU) 2015-01 which eliminates the concept of extraordinary items from U.S. GAAP. Entities will no longer be required to separately classify and present extraordinary items in the Consolidated Statements of Earnings. There was no material impact to EIPLP’s consolidated financial statements as a result of adopting this update. Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity Effective January 1, 2015, EIPLP prospectively adopted ASU 2014-08 which changes the criteria and disclosures for reporting discontinued operations. The revised criteria will in general result in fewer transactions being categorized as discontinued operations. There was no material impact to the consolidated financial statements as a result of adopting this update. FUTURE ACCOUNTING POLICY CHANGES Recognition and Measurement of Financial Assets and Liabilities ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. The amendments revise accounting related to the classification and measurement of investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value and the disclosure requirements associated with the fair value of financial instruments. EIPLP is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017 and is to be applied by means of a cumulative-effect adjustment to the Statement of Financial Position as of the beginning of the fiscal year of adoption, with amendments related to equity securities without readily determinable fair values to be applied prospectively. Classification of Deferred Taxes on the Statement of Financial Position ASU 2015-17 was issued in November 2015 with the intent to simplify the presentation of deferred income taxes. The amendments require that deferred tax liabilities and assets be classified as noncurrent in a Statement of Financial Position. The accounting update is effective for fiscal years beginning after December 15, 2016 and is to be applied on a prospective or retrospective basis. EIPLP is currently assessing the impact of the new standard on its consolidated financial statements. Early application is permitted for all entities as of the beginning of an interim or annual reporting period. Effective January 1, 2016, EIPLP will elect to early adopt ASU 2015-17.

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Simplifying the Accounting for Measurement-Period Adjustments in Business Combinations ASU 2015-16 was issued in September 2015 with the intent to simplify the accounting for measurement-period adjustments in business combinations. The new standard requires that an acquirer must recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The accounting update is effective for fiscal years beginning after December 15, 2015 and is to be applied on a prospective basis. The adoption of the pronouncement is not anticipated to have a material impact on EIPLP’s consolidated financial statements. Simplifying the Presentation of Debt Issuance Costs ASU 2015-03 was issued in April 2015 with the intent to simplify the presentation of debt issuance costs. The new standard requires a debt issuance cost related to a recognized debt liability to be presented in the Consolidated Statement of Financial Position as a direct deduction from the carrying amount of that debt liability, as consistent with the presentation of debt discounts or premiums. Further, ASU 2015-15 was issued in August 2015 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line-of-credit. The accounting updates are effective for financial statements issued for fiscal years beginning after December 15, 2015 on a retrospective basis. The adoption of the pronouncement is not anticipated to have a material impact on EIPLP’s consolidated financial statements. Amendments to the Consolidation Analysis ASU 2015-02, issued in February 2015, revises the current consolidation guidance which results in a change in the determination of whether an entity consolidates certain types of legal entities. EIPLP is currently assessing the impact of the new standard on its consolidated financial statements. The new standard is effective for annual and interim reporting periods beginning after December 15, 2015 and may be applied on a full or modified retrospective basis. Hybrid Financial Instruments Issued in the Form of a Share ASU 2014-16 was issued in November 2014 with the intent to eliminate the use of different methods in practice in the accounting for hybrid financial instruments issued in the form of a share. The new standard clarifies the evaluation of the economic characteristics and risks of a host contract in these hybrid financial instruments. EIPLP does not expect the adoption of ASU 2014-16 to have a material impact on its consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2015 and is to be applied on a modified retrospective basis. Development Stage Entities ASU 2014-10, issued in June 2014, amended the consolidation guidance to eliminate the development stage entity relief when applying the variable interest entity model and evaluating the sufficiency of equity at risk. EIPLP is currently evaluating the impact of the amendment to the consolidation guidance, which is effective for annual reporting periods beginning after December 15, 2015. The new standard requires these amendments be applied retrospectively. Revenue from Contracts with Customers ASU 2014-09 was issued in May 2014 with the intent of significantly enhancing comparability of revenue recognition practices across entities and industries. The new standard provides a single principles-based, five-step model to be applied to all contracts with customers and introduces new, increased disclosure requirements. EIPLP is currently assessing the impact of the new standard on its consolidated financial statements. In July 2015, the effective date of the new standard was delayed by one year and the new standard is now effective for annual and interim periods beginning on or after December 15, 2017 and may be applied on either a full or modified retrospective basis.

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THE FUND GROUP OWNERSHIP

The following presents the direct and indirect ownership of the Fund Group as at February 17, 2016: ENBRIDGE INCOME FUND HOLDINGS INC. (number of common shares outstanding)

Held by public 77,942,053 Held by Enbridge Inc. 19,366,333

97,308,386 ENBRIDGE INCOME FUND (number of ordinary trust units outstanding)

Held by Enbridge Inc.1 94,150,000 Held by Enbridge Income Fund Holdings Inc. 97,308,386

191,458,386 ENBRIDGE INCOME PARTNERS LP (number of units outstanding) Class A units

Held by Enbridge Income Partners GP Inc. 35,685 Held by Enbridge Commercial Trust 356,817,186

356,852,871 Class C units1

Held by Enbridge Inc. 442,923,363 Class D units2

Held by Enbridge Inc. 2,689,178 Class E unit

Held by Enbridge Inc. 1 Special Interest Rights

Held by Enbridge Inc. 1,000 1 The Fund Units and Class C units may, at the option of the holder, be exchanged in whole or in part for ECT Preferred Units,

Fund Units or ENF common shares. 2 The Class D units may, at the option of the holder, be exchanged for Class C units.

ENBRIDGE INCOME PARTNERS LP

CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015

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Independent Auditor’s Report To the Partners of Enbridge Income Partners LP We have audited the accompanying consolidated financial statements of Enbridge Income Partners LP, which comprise the consolidated statements of financial position as at December 31, 2015 and December 31, 2014 and the consolidated statements of earnings, comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2015, and the related notes, which comprise a summary of significant accounting policies and other explanatory information. Management’s responsibility for the consolidated financial statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. Auditor’s responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

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Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Enbridge Income Partners LP as at December 31, 2015 and December 31, 2014 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015 in accordance with accounting principles generally accepted in the United States of America.

Chartered Professional Accountants Calgary, Alberta February 19, 2016

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CONSOLIDATED STATEMENTS OF EARNINGS Year ended December 31, 20151 20141 20131 (millions of Canadian dollars) Revenues

Transportation and other services 1,501 1,877 1,916 Electricity sales 295 258 233 Revenues - affiliates (Note 23) 78 51 71

1,874 2,186 2,220 Expenses

Operating and administrative 1,068 1,087 1,070 Operating and administrative, net - affiliates (Note 23) 68 (124) (95) Depreciation and amortization 613 549 476 Environmental costs, net of recoveries (26) (5) 79

1,723 1,507 1,530 151 679 690 Income from equity investments (Note 10) 164 140 118 Other income/(expense) 50 26 (16) Other income - affiliates (Note 23) 83 97 88 Interest expense (Note 15) (20) (6) (76) Interest expense - affiliates (Note 15) (307) (310) (225) 121 626 579 Income taxes recovery/(expense) (Note 21) 59 5 (84) Earnings 180 631 495 Special interest rights distributions (Note 18)

Temporary performance distribution rights (58) - - Earnings attributable to general and limited partners 122 631 495 Earnings attributable to general partner interest (Note 18) - - - Earnings attributable to limited partners’ interests (Note 18) 122 631 495 122 631 495 The accompanying notes are an integral part of these consolidated financial statements. 1 Retrospectively adjusted to furnish comparative information related to the 2015 Transaction and the 2014 Transaction (Note 2).

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Year ended December 31, 20151 20141 20131 (millions of Canadian dollars) Earnings 180 631 495 Other comprehensive income/(loss), net of tax

Change in unrealized gains/(loss) on cash flow hedges (94) (119) 62 Reclassification to earnings of realized cash flow hedges 1 (1) 35 Reclassification to earnings of unrealized cash flow hedges 2 - (1) Change in foreign currency translation adjustment 80 5 5

Other comprehensive income/(loss) (11) (115) 101 Comprehensive income attributable to general and limited partners 169 516 596 The accompanying notes are an integral part of these consolidated financial statements. 1 Retrospectively adjusted to furnish comparative information related to the 2015 Transaction and the 2014 Transaction (Note 2).

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CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL Year ended December 31, 20151 20141 20131 (millions of Canadian dollars) General partner interest (Note 18)

Balance at beginning of year - - - Excess purchase price over historical carrying value acquired allocation

(Note 6) (1) - - Redemption value adjustment attributable to Class C and D units (1) - -

(2) - - Allocation from limited partners (6,418) - -

Balance at end of year (6,420) - - Limited partners’ interests (Note 18)

Balance at beginning of year - limited partners’ interests 3,165 1,929 2,068 Balance at beginning of year - Purchased Entities2 3,989 3,760 3,091 Units issued 3,874 1,760 - Excess purchase price over historical carrying value acquired allocation

(Note 6) (7,160) (392) 2 Equity of former owners of Purchased Entities allocation (1,489) (185) 338 Redemption value adjustment attributable to Class C and D units (8,241) - - Earnings allocation (10) 631 495 Distributions (546) (349) (305)

(6,418) 7,154 5,689 Allocation to general partner 6,418 - -

Balance at end of year - 7,154 5,689 Special interest rights (Note 18)

Balance at beginning of year - - - Units issued 2,565 - -

Balance at end of year 2,565 - - Accumulated other comprehensive income/(loss) (Note 19)

Balance at beginning of year (73) 42 (59) Other comprehensive income/(loss), net of tax (11) (115) 101

Balance at end of year (84) (73) 42 Total partners’ capital (3,939) 7,081 5,731 The accompanying notes are an integral part of these consolidated financial statements. 1 Retrospectively adjusted to furnish comparative information related to the 2015 Transaction and the 2014 Transaction (Note 2). 2 Refer to Note 2 for the description of Purchased Entities.

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CONSOLIDATED STATEMENTS OF CASH FLOWS Year ended December 31, 20151 20141 20131 (millions of Canadian dollars) Operating activities

Earnings 180 631 495 Depreciation and amortization 613 549 476 Deferred income taxes (recovery)/expense (Note 21) (214) (41) 131 Changes in unrealized loss on derivative instruments, net (Note 20) 1,495 519 444 Cash distributions in excess of equity earnings (12) 11 14 Hedge ineffectiveness 3 (3) (2) Unrealized gain on foreign intercompany loan (Note 20) (134) (16) - Gain on disposition (Note 7) (22) - - Derecognition of regulatory balances (10) - 12 Other 2 (2) (1)

Changes in operating assets and liabilities (Note 22) 48 52 (658) 1,949 1,700 911 Investing activities

Additions to property, plant and equipment (3,068) (4,356) (3,185) Long-term investments (45) (6) (130) Purchase of equity investment - (835) - Investment in affiliated company (Note 23) 160 2,530 (2,690) Additions to intangible assets (8) (117) (132) Long-term receivable from affiliate (Notes 20 and 23) 17 (691) - Acquisitions - - 2 Acquisition of Purchased Entities (2,712) Affiliate loans, net 325 1 - Proceeds from disposition 26 - - Changes in restricted cash - 2 -

(5,305) (3,472) (6,135) Financing activities

Affiliate loans, net (2,731) 558 3,881 Net change in bank indebtedness and short-term borrowings (105) 27 (159) Net change in commercial paper and credit facility draws 1,180 (105) 239 Southern Lights project financing repayments - (352) (5) Debenture and term note issues - Southern Lights - 352 - Debenture and term note issues 997 - 550 Debenture and term note repayments (262) (4) - Contributions received and shares issued by Acquired Interests (Notes 2, 6 and 10) 1,916 715 1,627 Distributions and dividends paid by Acquired Interests (Notes 2, 6 and 10) (811) (815) (725) Net proceeds from unit issuances (Note 18) 3,874 1,760 - Distributions to partners (737) (336) (301)

3,321 1,800 5,107 Effect of translation of foreign denominated cash and cash equivalents 2 - - Increase/(decrease) in cash and cash equivalents (33) 28 (117) Cash and cash equivalents at beginning of year 162 134 251 Cash and cash equivalents at end of year 129 162 134 Supplementary cash flow information

Income taxes (received)/paid 57 (16) 76 Interest paid 494 491 467

The accompanying notes are an integral part of these consolidated financial statements. 1 Retrospectively adjusted to furnish comparative information related to the 2015 Transaction and the 2014 Transaction (Note 2).

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CONSOLIDATED STATEMENTS OF FINANCIAL POSITION December 31, 20151 20141 (millions of Canadian dollars) Assets Current assets

Cash and cash equivalents 129 162 Accounts receivable and other (Note 8) 615 487 Accounts receivable from affiliates 47 41 Loans to affiliates (Note 23) 3 3

794 693 Property, plant and equipment, net (Note 9) 21,064 18,856 Long-term receivable from affiliate (Notes 20 and 23) 826 707 Loans to affiliates (Note 23) - 325 Investment in affiliated company (Notes 20 and 23) 514 160 Long-term investments (Note 10) 490 434 Restricted long-term investments (Note 11) 45 - Deferred amounts and other assets (Note 12) 1,532 1,372 Intangible assets, net (Note 13) 110 478 Goodwill 29 29 Deferred income taxes (Note 21) 246 242 25,650 23,296 Liabilities and partners’ capital Current liabilities

Bank indebtedness 33 35 Short-term borrowings (Note 15) - 103 Accounts payable and other (Note 14) 1,126 996 Accounts payable to affiliates 472 93 Distributions payable to affiliates 143 40 Interest payable 45 37 Loans from affiliates (Note 23) 95 8,367 Current maturities of long-term debt (Note 15) 14 264

1,928 9,935 Long-term debt (Note 15) 5,591 3,429 Other long-term liabilities (Note 16) 2,292 1,107 Loans from affiliates (Note 23) 5,801 260 Deferred income taxes (Note 21) 1,275 1,484 16,887 16,215 Commitments and contingencies (Note 24) Class C units (Note 18) 12,189 - Class D units (Note 18) 38 - Class E unit (Note 18) 475 - 12,702 - Partners’ capital

General partner’s capital deficit (Note 18) (6,420) - Limited partners’ capital (Note 18) - 7,154 Special interest rights (Note 18) 2,565 - Accumulated other comprehensive loss (Note 19) (84) (73)

(3,939) 7,081 25,650 23,296 The accompanying notes are an integral part of these consolidated financial statements. 1 Retrospectively adjusted to furnish comparative information related to the 2015 Transaction and the 2014 Transaction (Note 2). Approved by the Board of Directors of Enbridge Income Partners GP Inc., the General Partner of Enbridge Income Partners LP: “signed” “signed” Bruce G. Waterman E.F.H. Roberts Director Director

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. GENERAL BUSINESS DESCRIPTION Enbridge Income Partners LP (EIPLP) is involved in the generation, transportation and storage of energy through interests in its liquids pipelines business, including the Canadian Mainline, its 50% interest in the Canadian and United States portions of Alliance Pipeline, which transports natural gas, and its renewable and alternative power generation facilities. EIPLP was formed in 2002. EIPLP is a partnership between Enbridge Commercial Trust (ECT) and Enbridge Inc. (Enbridge). Enbridge is a North American transporter, distributor and generator of energy. ECT is a wholly-owned investment of Enbridge Income Fund (the Fund). The unitholders of the Fund are Enbridge Income Fund Holdings Inc. (ENF), a public company listed on the Toronto Stock Exchange (TSX), and Enbridge, a public company listed on the TSX and New York Stock Exchange. Enbridge has a controlling interest in the general partner of EIPLP which has the right to manage, control and operate the businesses of EIPLP. Enbridge also acts as a sponsor to ENF and all of ENF’s direct and indirect investments, as well as EIPLP. The Fund, ECT, EIPLP and its subsidiaries are referred to as the Fund Group. On September 1, 2015, upon closing of the acquisition of the Canadian Liquids Pipelines and certain Canadian renewable energy assets from Enbridge and certain Enbridge subsidiaries (the 2015 Transaction), Enbridge held an approximate 57% interest in EIPLP with the remaining 43% held by ECT. Additionally, Enbridge now holds a 51% direct interest in the general partner of EIPLP. EIPLP conducts its business through three business segments: Liquids Pipelines, Gas Pipelines and Green Power. These operating segments are strategic business units established by senior management to facilitate the achievement of EIPLP’s long-term objectives and the objectives of EIPLP’s partners, as well as to aid in resource allocation decisions and to assess operational performance. Financing costs, current and deferred income taxes and other costs not attributable to specific business segments are presented on a consolidated basis. LIQUIDS PIPELINES Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids and refined products pipelines, feeder pipelines, gathering systems and terminals in Canada, including Canadian Mainline, Regional Oil Sands System, Southern Lights Pipeline, which includes the Canadian portion of Southern Lights (Southern Lights Canada) and Class A units of the United States portion of Southern Lights (Southern Lights US), and Feeder Pipelines and Other. GAS PIPELINES Gas Pipelines includes EIPLP’s 50% interest in both the Canadian and United States portions of the Alliance Pipeline system, which transports liquids-rich natural gas from northeast British Columbia, northwest Alberta and the Bakken area of North Dakota to Channahon, Illinois. GREEN POWER Green Power includes renewable and alternative energy generating facilities, consisting of wind farms located in Alberta, Saskatchewan, Ontario and Quebec and solar facilities located in Ontario. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). Amounts are stated in Canadian dollars unless otherwise noted. EIPLP is permitted to use U.S. GAAP as its primary basis of accounting to enable the Fund to meet its continuous disclosure obligations under an exemption granted by securities regulators in Canada.

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BASIS OF PRESENTATION AND USE OF ESTIMATES On September 1, 2015, EIPLP acquired 100% interests in the following entities as part of the 2015 Transaction (collectively, the Purchased Entities):

• Enbridge Pipelines Inc. (EPI) • Enbridge Pipelines (Athabasca) Inc. (EPAI) • Enbridge Hardisty Storage Inc. • Enbridge Southern Lights GP Inc. • Enbridge Lac Alfred Wind Project GP Inc. • Enbridge Massif du Sud Wind Project GP Inc. • Enbridge Blackspring Ridge I Wind Project GP Inc. • Enbridge Saint Robert Bellarmin Wind Project GP Inc.

On November 7, 2014, EIPLP completed a transaction whereby indirect wholly-owned subsidiaries of EIPLP acquired from Enbridge a 50% equity interest in the United States portion of Alliance Pipeline (Alliance Pipeline US) and subscribed for and purchased Class A Units of Enbridge subsidiaries which provide a defined cash flow stream from Southern Lights US (the 2014 Transaction). The interests acquired in the 2015 Transaction and 2014 Transaction (collectively, the Acquired Interests) were accounted for as transactions among entities under common control, similar to a pooling of interests, whereby the assets and liabilities acquired were recorded at Enbridge’s historic carrying values. Earnings for the years ended December 31, 2015, 2014 and 2013 report the results of operations of the Acquired Interests as though the acquisitions occurred at the beginning of the earliest period presented in these financial statements. Similarly, comparative information for prior years has been retrospectively adjusted to present the results of operations for EIPLP and the Acquired Interests on a combined basis. See Notes 6 and 10 for additional disclosure regarding the acquisitions of the Purchased Entities and Alliance Pipeline US, respectively. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: carrying values of regulatory assets and liabilities (Note 5); unbilled revenues (Note 8); allowance for doubtful accounts; depreciation rates and carrying value of property, plant and equipment (Note 9); amortization rates of intangible assets (Note 13); measurement of goodwill; fair value of asset retirement obligations (ARO) (Note 17); fair value of financial instruments (Note 20); provisions for income taxes (Note 21); and commitments and contingencies (Note 24). Actual results could differ from these estimates. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of EIPLP and its subsidiaries for which it is the primary beneficiary. Upon inception of a contractual agreement, EIPLP performs an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a variable interest entity (VIE). Where EIPLP concludes it is the primary beneficiary of a VIE, it will consolidate the accounts of that entity. The consolidated financial statements also include the accounts of any limited partnerships where EIPLP, based on all facts and circumstances, controls such limited partnerships. For certain investments where EIPLP retains an undivided interest in assets and liabilities, EIPLP records its proportionate share of assets, liabilities, revenues and expenses. All significant intercompany accounts and transactions are eliminated upon consolidation. Investments and entities over which EIPLP exercises significant influence are accounted for using the equity method. EARNINGS ALLOCATION EIPLP allocates earnings based on the Hypothetical Liquidation at Book Value (HLBV) method. EIPLP applies the HLBV method for allocation of earnings and other comprehensive income (OCI) where cash distributions, including both preference and residual distributions are not based on the investor’s ownership percentages. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that the partners would receive if EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the respective partners. The difference

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between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is the partners’ share of the earnings or loss from EIPLP for the period. The limited partners' capital accounts are limited to the balance of their capital account and any allocation that draws the account to a deficit position is reallocated to the general partner. REGULATION Certain of EIPLP’s businesses are subject to regulation by various authorities including, but not limited to, the National Energy Board (NEB), the Federal Energy Regulatory Commission (FERC), the Alberta Energy Regulator, Saskatchewan Ministry of Economy (SME) and Manitoba Mineral Resources. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non rate-regulated entities. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the NEB’s Land Matters Consultation Initiative (LMCI). Long-term regulatory assets are recorded in Deferred amounts and other assets and current regulatory assets are recorded in Accounts receivable and other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts payable and other. Regulatory assets are assessed for impairment if EIPLP identifies an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions or expected future actions of the regulator. To the extent that the regulator’s actions differ from EIPLP’s expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, EIPLP would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component which are both capitalized based on rates set out in a regulatory agreement. In the absence of rate regulation, EIPLP would capitalize interest using a capitalization rate based on its cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation would not be recognized. For certain regulated operations to which U.S. GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with U.S. GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with U.S. GAAP and no deferred regulatory asset is recorded (Note 5). REVENUE RECOGNITION For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer credit worthiness is assessed prior to agreement signing as well as throughout the contract duration. Certain revenues from liquids and gas pipeline businesses are recognized under the terms of committed delivery contracts rather than the cash tolls received. Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts rateably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry periods. EIPLP recognizes revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote.

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For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. From July 1, 2011 onward, Canadian Mainline (excluding Lines 8 and 9) earnings are governed by the Competitive Toll Settlement (CTS), under which revenues are recorded when services are performed. Effective on that date, EIPLP prospectively discontinued the application of rate-regulated accounting for those assets with the exception of flow-through income taxes covered by a specific rate order. DERIVATIVE INSTRUMENTS AND HEDGING Non-qualifying Derivatives Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Transportation and other services revenues, Electricity sales revenues, Operating and administrative expense, Other income/(expense) and Interest expense. Derivatives in Qualifying Hedging Relationships EIPLP uses derivative financial instruments to manage its exposure to changes in commodity prices, foreign exchange rates and interest rates. Hedge accounting is optional and requires EIPLP to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. EIPLP presents the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges or fair value hedges. Cash Flow Hedges EIPLP uses cash flow hedges to manage its exposure to changes in commodity prices, foreign exchange rates and interest rates. The effective portion of the change in the fair value of a cash flow hedging instrument is recorded in OCI and is reclassified to earnings when the hedged item impacts earnings. Any hedge ineffectiveness is recorded in current period earnings. If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized concurrently with the related transaction. If a hedged anticipated transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur. Fair Value Hedges EIPLP may use fair value hedges to hedge the fair value of debt instruments or commodity positions. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged asset or liability, otherwise required to be carried at cost or amortized cost, ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. Classification of Derivatives EIPLP recognizes the fair market value of derivative instruments on the Consolidated Statements of Financial Position as current and long-term assets or liabilities depending on the timing of the settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current. Cash inflows and outflows related to derivative instruments are classified as Operating activities on the Consolidated Statements of Cash Flows. Balance Sheet Offset Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when EIPLP has the legal right and intention to settle them on a net basis.

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Transaction Costs Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. EIPLP incurs transaction costs primarily from the issuance of debt and classifies these costs as Deferred amounts and other assets. These costs are amortized using the effective interest rate method over the life of the related debt instrument. EQUITY INVESTMENTS Equity investments over which EIPLP exercises significant influence, but does not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for EIPLP’s proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to and decreased for distributions received from the investees. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, EIPLP capitalizes interest costs associated with its investment during such period. RESTRICTED LONG-TERM INVESTMENTS Long-term investments that are restricted as to withdrawal or usage, for the purposes of the NEB’s LMCI, are presented as Restricted long-term investments on the Consolidated Statements of Financial Position. INCOME TAXES Pursuant to the Income Tax Act (Canada), EIPLP, as a partnership, is not subject to income taxes. However, subsidiary corporations are taxable and applicable income taxes have been reflected in these consolidated financial statements. The liability method of accounting for income taxes is followed for subsidiary corporations. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For EIPLP’s regulated operations, a deferred income tax liability is recognized with a corresponding regulatory asset to the extent taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in Income taxes. FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which EIPLP or a subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date. Exchange gains and losses resulting from translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period in which they arise. Gains and losses arising from translation of foreign operations’ functional currencies to EIPLP’s Canadian dollar presentation currency are included in the cumulative translation adjustment component of Accumulated other comprehensive income/(loss) (AOCI) and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect on the balance sheet date, while revenues and expenses are translated using monthly average exchange rates. CASH AND CASH EQUIVALENTS Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased. RESTRICTED CASH Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific commercial arrangements, are presented as Restricted cash on the Consolidated Statements of Financial Position.

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LOANS AND RECEIVABLES Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost. Interest income is recognized in earnings as it is earned with the passage of time. ALLOWANCE FOR DOUBTFUL ACCOUNTS Allowance for doubtful accounts is determined based on collection history. When EIPLP has determined that further collection efforts are unlikely to be successful, amounts charged to the allowance for doubtful accounts are applied against the impaired accounts receivable. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. EIPLP capitalizes interest incurred during construction for non rate-regulated assets. For rate-regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component. Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogenous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to accumulated depreciation. DEFERRED AMOUNTS AND OTHER ASSETS Deferred amounts and other assets primarily include: costs which regulatory authorities have permitted, or are expected to permit, to be recovered through future rates including deferred income taxes; contractual receivables under the term of long-term delivery contracts; derivative financial instruments; and deferred financing costs. Deferred financing costs are amortized using the effective interest method over the term of the related debt and are recorded in Interest expense. GOODWILL Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually, or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. For the purposes of impairment testing, reporting units are identified as business operations within an operating segment. EIPLP has the option to first assess qualitative factors to determine whether it is necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test is performed, the first step involves determining the fair value of EIPLP’s reporting units inclusive of goodwill and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured as the excess of the carrying amount of the reporting unit’s allocated goodwill over the implied fair value of the goodwill based on the fair value of the reporting unit’s assets and liabilities. INTANGIBLE ASSETS Intangible assets consist primarily of certain software costs, acquired power purchase agreements, land leases and permits. EIPLP capitalizes costs incurred during the application development stage of internal use software projects. Intangible assets are amortized on a straight-line basis over their expected lives, commencing when the asset is available for use. IMPAIRMENT EIPLP reviews the carrying values of its long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the asset, the asset is written down to fair value.

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With respect to investments in debt and equity securities, EIPLP assesses at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is determined to be objective evidence of impairment, EIPLP internally values the expected discounted cash flows using observable market inputs and determines whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset. With respect to other financial assets, EIPLP assesses the assets for impairment when it no longer has reasonable assurance of timely collection. If evidence of impairment is noted, EIPLP reduces the value of the financial asset to its estimated realizable amount, determined using discounted expected future cash flows. ASSET RETIREMENT OBLIGATIONS ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. EIPLP’s estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. For the majority of EIPLP’s assets, it is not possible to make a reasonable estimate of ARO due to the indeterminate timing and scope of the asset retirements. COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES EIPLP expenses or capitalizes, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. EIPLP expenses costs incurred for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. EIPLP records liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. EIPLP’s estimates are subject to revision in future periods based on actual costs or new information and are included in Accounts payable and other and Other long-term liabilities in the Consolidated Statements of Financial Position at their undiscounted amounts. There is always a potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. EIPLP evaluates recoveries from insurance coverage separately from the liability and, when recovery is probable, EIPLP records and reports an asset separately from the associated liability in the Consolidated Statements of Financial Position. Liabilities for commitments and contingencies are recognized when, after fully analysing available information, EIPLP determines it is either probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, EIPLP recognizes the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. EIPLP expenses legal costs associated with loss contingencies as such costs are incurred.

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3. CHANGES IN ACCOUNTING POLICIES ADOPTION OF NEW STANDARDS Extraordinary and Unusual Items Effective January 1, 2015, EIPLP retrospectively adopted Accounting Standards Update (ASU) 2015-01 which eliminates the concept of extraordinary items from U.S. GAAP. Entities will no longer be required to separately classify and present extraordinary items in the Consolidated Statements of Earnings. There was no material impact to EIPLP’s consolidated financial statements as a result of adopting this update. Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity Effective January 1, 2015, EIPLP prospectively adopted ASU 2014-08 which changes the criteria and disclosures for reporting discontinued operations. The revised criteria will in general result in fewer transactions being categorized as discontinued operations. There was no material impact to the consolidated financial statements as a result of adopting this update. FUTURE ACCOUNTING POLICY CHANGES Recognition and Measurement of Financial Assets and Liabilities ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. The amendments revise accounting related to the classification and measurement of investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value and the disclosure requirements associated with the fair value of financial instruments. EIPLP is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017 and is to be applied by means of a cumulative-effect adjustment to the Statement of Financial Position as of the beginning of the fiscal year of adoption, with amendments related to equity securities without readily determinable fair values to be applied prospectively. Classification of Deferred Taxes on the Statement of Financial Position ASU 2015-17 was issued in November 2015 with the intent to simplify the presentation of deferred income taxes. The amendments require that deferred tax liabilities and assets be classified as noncurrent in a Statement of Financial Position. The accounting update is effective for fiscal years beginning after December 15, 2016 and is to be applied on a prospective or retrospective basis. EIPLP is currently assessing the impact of the new standard on its consolidated financial statements. Early application is permitted for all entities as of the beginning of an interim or annual reporting period. Effective January 1, 2016, EIPLP will elect to early adopt ASU 2015-17. Simplifying the Accounting for Measurement-Period Adjustments in Business Combinations ASU 2015-16 was issued in September 2015 with the intent to simplify the accounting for measurement-period adjustments in business combinations. The new standard requires that an acquirer must recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The accounting update is effective for fiscal years beginning after December 15, 2015 and is to be applied on a prospective basis. The adoption of the pronouncement is not anticipated to have a material impact on EIPLP’s consolidated financial statements. Simplifying the Presentation of Debt Issuance Costs ASU 2015-03 was issued in April 2015 with the intent to simplify the presentation of debt issuance costs. The new standard requires a debt issuance cost related to a recognized debt liability to be presented in the Consolidated Statement of Financial Position as a direct deduction from the carrying amount of that debt liability, as consistent with the presentation of debt discounts or premiums. Further, ASU 2015-15 was issued in August 2015 to clarify the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line-of-credit. The accounting updates are effective for financial statements issued for fiscal years beginning after December 15, 2015 on a retrospective basis. The adoption of the pronouncement is not anticipated to have a material impact on EIPLP’s consolidated financial statements.

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Amendments to the Consolidation Analysis ASU 2015-02, issued in February 2015, revises the current consolidation guidance which results in a change in the determination of whether an entity consolidates certain types of legal entities. EIPLP is currently assessing the impact of the new standard on its consolidated financial statements. The new standard is effective for annual and interim reporting periods beginning after December 15, 2015 and may be applied on a full or modified retrospective basis. Hybrid Financial Instruments Issued in the Form of a Share ASU 2014-16 was issued in November 2014 with the intent to eliminate the use of different methods in practice in the accounting for hybrid financial instruments issued in the form of a share. The new standard clarifies the evaluation of the economic characteristics and risks of a host contract in these hybrid financial instruments. EIPLP does not expect the adoption of ASU 2014-16 to have a material impact on its consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2015 and is to be applied on a modified retrospective basis. Development Stage Entities ASU 2014-10, issued in June 2014, amended the consolidation guidance to eliminate the development stage entity relief when applying the VIE model and evaluating the sufficiency of equity at risk. EIPLP is currently evaluating the impact of the amendment to the consolidation guidance, which is effective for annual reporting periods beginning after December 15, 2015. The new standard requires these amendments be applied retrospectively. Revenue from Contracts with Customers ASU 2014-09 was issued in May 2014 with the intent of significantly enhancing comparability of revenue recognition practices across entities and industries. The new standard provides a single principles-based, five-step model to be applied to all contracts with customers and introduces new, increased disclosure requirements. EIPLP is currently assessing the impact of the new standard on its consolidated financial statements. In July 2015, the effective date of the new standard was delayed by one year and the new standard is now effective for annual and interim periods beginning on or after December 15, 2017 and may be applied on either a full or modified retrospective basis.

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4. SEGMENTED INFORMATION

Year ended December 31, 2015

Liquids Pipelines

Gas Pipelines

Green Power

Eliminations and Other Consolidated

(millions of Canadian dollars) Revenues 1,552 - 322 - 1,874 Operating and administrative (1,060) - (58) (18) (1,136) Depreciation and amortization (504) - (109) - (613) Environmental costs, net of recoveries 26 - - - 26 14 - 155 (18) 151 Income/(loss) from equity investments - 166 (2) - 164 Other income/(expense) (15) (22) 1 169 133 Earnings/(loss) before interest and taxes (1) 144 154 151 448 Interest expense (327) Income taxes recovery 59 Special interest rights distributions (58) Earnings attributable to general and limited partners 122 Additions to property, plant and equipment1 3,064 - 4 - 3,068 Total assets 22,016 438 2,363 833 25,650 Year ended December 31, 2014

Liquids Pipelines

Gas Pipelines

Green Power

Eliminations and Other Consolidated

(millions of Canadian dollars) Revenues 1,910 - 276 - 2,186 Operating and administrative (906) - (56) (1) (963) Depreciation and amortization (454) - (95) - (549) Environmental costs, net of recoveries 5 - - - 5 555 - 125 (1) 679 Income from equity investments - 138 2 - 140 Other income/(expense) 20 (6) - 109 123 Earnings before interest and taxes 575 132 127 108 942 Interest expense (316) Income taxes recovery 5 Earnings attributable to general and limited partners 631 Additions to property, plant and equipment1 4,155 - 204 - 4,359 Total assets 19,460 401 2,468 967 23,296 Year ended December 31, 2013

Liquids Pipelines

Gas Pipelines

Green Power

Eliminations and Other Consolidated

(millions of Canadian dollars) Revenues 1,987 - 233 - 2,220 Operating and administrative (853) - (121) (1) (975) Depreciation and amortization (396) - (80) - (476) Environmental costs, net of recoveries (79) - - - (79) 659 - 32 (1) 690 Income from equity investments - 117 1 - 118 Other income/(expense) (12) - - 84 72 Earnings before interest and taxes 647 117 33 83 880 Interest expense (301) Income taxes expense (84) Earnings attributable to general and limited partners 495 Additions to property, plant and equipment1 2,880 - 308 - 3,188 1 Includes allowance for equity funds used during construction of nil for the year ended December 31, 2015 (2014 - $3 million;

2013 - $3 million). The measurement basis for preparation of segmented information is consistent with the significant accounting policies (Note 2).

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5. FINANCIAL STATEMENT EFFECTS OF RATE REGULATION GENERAL INFORMATION ON RATE REGULATION AND ITS ECONOMIC EFFECTS A number of businesses within EIPLP are subject to regulation. EIPLP’s significant regulated businesses and related accounting impacts are described below. Canadian Mainline Canadian Mainline includes the Canadian portion of the mainline system and is subject to regulation by the NEB. Canadian Mainline tolls (excluding Lines 8 and 9) are currently governed by the 10-year CTS, which establishes a Canadian Local Toll for all volumes shipped on the Canadian Mainline and an International Joint Tariff for all volumes shipped from western Canadian receipt points to delivery points on the Lakehead System and delivery points on the Canadian Mainline downstream of the Lakehead System. The CTS was negotiated with shippers in accordance with NEB guidelines, was approved by the NEB in June 2011 and took effect July 1, 2011. Under the CTS, a regulatory asset is recognized to offset deferred income taxes as a NEB rate order governing flow-through income tax treatment permits future recovery. No other material regulatory assets or liabilities are recognized under the terms of the CTS. Southern Lights Pipeline Southern Lights Canada is regulated by the NEB. Shippers on the Southern Lights Pipeline are subject to long-term transportation contracts under a cost of service toll methodology. Toll adjustments are filed annually with the regulators. Tariffs provide for recovery of allowable operating and debt financing costs, plus a pre-determined after-tax rate of return on equity of 10%. Southern Lights Pipeline tolls are based on a deemed 70% debt and 30% equity structure. Saskatchewan Gathering System The Saskatchewan Gathering System is regulated by SME. The Saskatchewan Gathering System follows a cost of service methodology. Tolls are subject to change from time to time based on differences between the estimated cost of service and actual costs incurred and include a 6.5% return on rate base. Alliance Pipeline Alliance Pipeline is comprised of two portions. The Canadian portion of Alliance Pipeline (Alliance Pipeline Canada) has tolls and tariffs regulated by the NEB and Alliance Pipeline US has tolls and tariffs regulated by the FERC. With the expiration of Alliance Pipeline’s transportation service agreements in December 2015, Alliance Pipeline announced a New Services Framework and the related tolls and tariff provisions required to implement the new services (collectively, New Services Framework). Pursuant to the New Services Framework, Alliance Pipeline retains exposure to potential variability in certain future costs and throughput volumes. As such, the majority of Alliance Pipeline’s operations no longer meet all of the criteria required for the continued application of rate-regulated accounting treatment and derecognition of regulatory balances as at June 30, 2015 was required. EIPLP’s equity pick-up of Alliance Pipeline, recorded in Income from equity investments on the Consolidated Statements of Earnings, included a one-time, non-cash gain of $8 million, before tax of $3 million, due to the derecognition of regulatory liabilities within Alliance Pipeline. Further, EIPLP recorded a one-time, non-cash loss of $16 million within Income taxes on the Consolidated Statements of Earnings related to the regulatory asset that had previously been recorded in respect of Alliance Pipeline Canada deferred income tax.

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FINANCIAL STATEMENT EFFECTS Accounting for rate-regulated activities has resulted in the recognition of the following significant regulatory assets and liabilities: December 31, 2015 2014

(millions of Canadian dollars) Regulatory assets/(liabilities) Liquids Pipelines Deferred income taxes1 1,048 898 Transportation revenue adjustment2 11 36 Pipeline future abandonment costs3 (43) - Tolling deferrals4 (39) (39)

Gas Pipelines Deferred income taxes1 - 24

1 The deferred income tax asset represents the regulatory offset to deferred income tax liabilities that are expected to be recovered under flow-through income tax treatment. The recovery period depends on future reversal of temporary differences.

2 The transportation revenue adjustment is the cumulative difference between actual expenses incurred and estimated expenses included in transportation tolls. Transportation revenue adjustments are not included in the rate base. To the extent that the regulator’s actions differ from EIPLP’s expectations, the amount of the transportation revenue adjustment ultimately recovered could differ significantly from the amounts recorded. The recovery period is approximately five years, commencing with tolls filed and in effect on January 1, 2015, and dependent on shipper throughput levels.

3 The pipeline future abandonment costs liability results from amounts collected and set aside in accordance with the NEB’s LMCI to cover future abandonment costs for NEB regulated Canadian pipelines. Funds collected are included in Restricted long-term investments (Note 11). Concurrently, EIPLP reflects the future abandonment cost as a regulatory liability. The settlement of this balance will occur as pipeline abandonment costs are incurred.

4 The tolling deferrals reflect net tax benefits expected to be refunded through future transportation tolls on Southern Lights Canada. The balance is expected to accumulate through 2018 before being refunded through tolls. Tolling deferrals are not included in the rate base.

OTHER ITEMS AFFECTED BY RATE REGULATION Allowance for Funds Used During Construction and Other Capitalized Costs Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains and losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified.

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6. ACQUISITIONS PURCHASED ENTITIES On September 1, 2015, EIPLP acquired 100% interests in the Purchased Entities from Enbridge and certain subsidiaries of Enbridge. Consideration was $33.2 billion. The components of the consideration for this acquisition were as follows: September 1, 2015 (millions of Canadian dollars, except for unit amounts) Cash1 2,712 Class C units (442,923,363 units at $35.44 per unit) (Note 18) 15,697 Class E unit (Note 18) 475 Special interest rights (1,000 units) (Note 18) 2,565 Long-term debt assumed 11,707 33,156 1 Includes working capital adjustments. The acquisition of the Purchased Entities was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the Purchased Entities were recorded at Enbridge’s historic carrying values, with any difference from consideration paid charged to partners’ capital. The purchase price was recorded as follows: September 1, 2015 (millions of Canadian dollars) Cash 37 Accounts receivable and other 426 Accounts receivable from affiliates 13 Property, plant and equipment, net 18,192 Investment in affiliated company (Note 23) 514 Long-term investments 22 Deferred amounts and other assets 1,410 Intangible assets, net 136 Accounts payable and other (912) Accounts payable to affiliates (311) Interest payable (42) Other long-term liabilities (1,970) Loans from affiliates (Note 23) (239) Deferred income taxes (892) 16,384

Excess purchase price over book value of net assets acquired 16,772 Total consideration 33,156 The allocation of the purchase price was based on information available at the time the consolidated financial statements were prepared. Accordingly, the allocation is subject to change as the purchase price is subject to final working capital adjustments and the impact of such changes may be material. Earnings for the years ended December 31, 2015, 2014 and 2013 include the results of the 2015 Transaction as though the acquisition occurred at the beginning of 2013. Similarly, comparative information for the prior years has been retrospectively adjusted to present the results of operations for EIPLP and the Purchased Entities on a combined basis.

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OTHER ACQUISITIONS In December 2014, EPI, a subsidiary of EIPLP, acquired an incremental 30% interest in the Massif du Sud Wind Project (Massif du Sud) for cash consideration of $102 million, bringing its total interest in the wind project to 80%. EPI acquired its original 50% interest in Massif du Sud in December 2012. EPI’s interest in Massif du Sud represents an undivided interest, with $97 million of the incremental purchase allocated to Property, plant and equipment and the remainder allocated to Intangible assets. Massif du Sud is operational and is presented within the Green Power segment. In October 2014, EPI acquired an incremental 17.5% interest in the Lac Alfred Wind Project (Lac Alfred) for cash consideration of $121 million, bringing its total interest in the wind project to 67.5%. EPI acquired its original 50% interest in Lac Alfred in December 2011. EPI’s interest in Lac Alfred represents an undivided interest, with $115 million of the incremental purchase allocated to Property, plant and equipment and the remainder allocated to Intangible assets. Lac Alfred is operational and is presented within the Green Power segment. In July 2013, EPI acquired a 50% undivided interest in the Saint Robert Bellarmin Wind Project (Saint Robert) for a purchase price of $106 million, of which $100 million was allocated to Property, plant and equipment, with the remainder allocated to Intangible assets. Saint Robert is operational and is presented within the Green Power segment. 7. DISPOSITION On May 1, 2015, EIPLP sold certain Virden crude oil pipeline system assets to an unrelated party for proceeds of $26 million before closing costs. The gain on disposition was $22 million, before tax of $3 million, and was presented within Other income/(expense) on the Consolidated Statements of Earnings. 8. ACCOUNTS RECEIVABLE AND OTHER December 31, 2015 2014 (millions of Canadian dollars) Unbilled revenues 164 141 Trade receivables 294 168 Taxes receivable 2 72 Short-term portion of derivative assets (Note 20) 7 1 Inventory 3 5 Prepaid expenses and deposits 72 39 Current deferred income taxes (Note 21) 40 22 Other 33 39 615 487

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9. PROPERTY, PLANT AND EQUIPMENT Weighted Average

December 31, Depreciation Rate 2015 2014 (millions of Canadian dollars) Liquids Pipelines Pipeline 2.5% 13,192 7,763 Pumping equipment, buildings, tanks and other 2.7% 6,922 7,538 Land and right-of-way 2.6% 244 154 Under construction - 2,718 4,955 23,076 20,410

Accumulated depreciation (4,174) (3,812) 18,902 16,598

Green Power Wind turbines, solar panels and other 4.0% 2,593 2,588 Under construction - 3 1 2,596 2,589

Accumulated depreciation (434) (331) 2,162 2,258

21,064 18,856 Depreciation expense for the year ended December 31, 2015 was $573 million (2014 - $513 million; 2013 - $452 million). 10. LONG-TERM INVESTMENTS Ownership December 31, Interest 2015 2014 (millions of Canadian dollars) EQUITY INVESTMENTS Gas Pipelines Alliance Pipeline 50% 436 375 Green Power NRGreen Power Limited Partnership 50% 50 54 Other 50% 4 5 490 434 Summarized combined financial information of EIPLP’s interests accounted for under the equity method is as follows: Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Revenues 464 445 414 Operating and administrative expense (139) (145) (136) Depreciation and amortization (111) (106) (102) Other income 5 2 2 Interest expense (55) (56) (60) Earnings before income taxes 164 140 118

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December 31, 2015 2014 (millions of Canadian dollars) Current assets 103 120 Property, plant and equipment, net 1,211 1,228 Deferred amounts and other assets 27 15 Current liabilities (108) (228) Long-term debt (720) (683) Other long-term liabilities (23) (18) Net assets 490 434 Certain assets of Alliance Pipeline are pledged as collateral to Alliance Pipeline’s lenders. On November 7, 2014, EIPLP acquired a 50% equity interest in Alliance Pipeline US from indirect wholly-owned subsidiaries of Enbridge. The purchase was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the investment in Alliance Pipeline US was recorded at Enbridge’s historic carrying values, with any difference from consideration paid charged to Partners’ capital. The excess of consideration over the historical carrying values is as follows: November 7, 2014 (millions of Canadian dollars) Equity investment, historical carrying value 205 Deferred income taxes 246 Cumulative translation adjustment (8) 443 Excess purchase price over historical carrying value of net assets acquired 392 Cash consideration 835 A deferred income tax asset has been recognized for the future tax consequences of differences between carrying amounts of assets and liabilities and their respective tax bases. The difference between the deferred income tax asset recorded by EIPLP and the historical carrying value of deferred taxes by Enbridge is recorded directly in Partners’ capital within the consolidated financial statements. 11. RESTRICTED LONG-TERM INVESTMENTS Effective January 1, 2015, EIPLP began collecting and setting aside funds to cover future pipeline abandonment costs for all NEB regulated pipelines as a result of the NEB’s regulatory requirements under LMCI. The funds collected are held in trusts in accordance with the NEB decision. The funds collected from shippers are reported within Transportation and other services revenues on the Consolidated Statements of Earnings and Restricted long-term investments on the Consolidated Statements of Financial Position. Concurrently, EIPLP reflects the future abandonment cost as an increase to Operating and administrative expense on the Consolidated Statements of Earnings and Other long-term liabilities on the Consolidated Statements of Financial Position. As at December 31, 2015, EIPLP had restricted long-term investments held in trust, invested in Canadian Treasury bonds, and are classified as held for sale and carried at fair value of $45 million (2014 - nil). As at December 31, 2015, EIPLP had estimated future abandonment costs of $43 million (2014 - nil) and restricted cash of nil (2014 - nil) related to LMCI.

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12. DEFERRED AMOUNTS AND OTHER ASSETS December 31, 2015 2014 (millions of Canadian dollars) Regulatory assets (Note 5) 1,066 966 Contractual receivables 437 382 Long-term portion of derivative assets (Note 20) 9 17 Deferred financing costs 20 7 1,532 1,372 As at December 31, 2015, deferred amounts of $49 million (2014 - $43 million) were subject to amortization and are presented net of accumulated amortization of $22 million (2014 - $20 million). Amortization expense for the year ended December 31, 2015 was $2 million (2014 - $3 million; 2013 - $3 million). 13. INTANGIBLE ASSETS Weighted Average Accumulated December 31, 2015 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Software 10.0% 54 36 18 Power purchase agreements 4.2% 72 11 61 Land leases, permits and other 4.1% 35 4 31 161 51 110 Weighted Average Accumulated December 31, 2014 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Software 8.8% 497 115 382 Power purchase agreements 4.0% 72 8 64 Land leases, permits and other 4.0% 35 3 32 604 126 478 Amortization expense for intangible assets for the year ended December 31, 2015 was $36 million (2014 - $33 million; 2013 - $21 million). EIPLP expects amortization expense for intangible assets for the years ending December 31, 2016 through 2020 of $9 million, $9 million, $8 million, $8 million and $8 million, respectively. 14. ACCOUNTS PAYABLE AND OTHER December 31, 2015 2014 (millions of Canadian dollars) Operating accrued liabilities 228 251 Trade payables 110 59 Construction payables 316 355 Deferred revenue 171 97 Current derivative liabilities (Note 20) 87 10 Contractor holdbacks 115 171 Taxes payable 59 - Other 40 53 1,126 996

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15. DEBT Weighted Average December 31, Interest Rate Maturity 2015 2014 (millions of Canadian dollars) Liquids Pipelines Debentures 8.2% 2024 200 200 Medium-term notes1,2 4.6% 2018-2045 4,061 3,323 Commercial paper and credit facility draws 1,346 163 Other3 4 9 Green Power Promissory note4 - 103 Other5 (6) (2) Total debt 5,605 3,796 Current maturities (14) (264) Short-term borrowings - (103) Long-term debt 5,591 3,429 1 Included in medium-term notes is $100 million with a maturity date of 2112. 2 On August 18, 2014, long-term private debt was issued for $352 million related to Southern Lights project financing. The

proceeds were utilized to repay the construction credit facilities on a dollar-for-dollar basis. 3 Primarily capital lease obligations. 4 A non-interest bearing demand promissory note that was paid on January 9, 2015. 5 Primarily debt discount. For the years ending December 31, 2016 through 2020, debenture and term note maturities are $14 million, $16 million, $318 million, $317 million, $365 million, respectively, and $3,231 million thereafter. EIPLP’s debentures and term notes bear interest at fixed rates and the interest obligations for the years ending December 31, 2016 through 2020 are $204 million, $197 million, $209 million, $182 million and $161 million, respectively. As at December 31, 2015 and 2014, all debt was unsecured. INTEREST EXPENSE Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Debentures and term notes 194 165 150 Commercial paper and credit facility draws 7 3 1 Southern Lights project financing - 13 13 Interest on loans from affiliated companies (Note 23) 307 310 225 Capitalized (181) (175) (88) 327 316 301 CREDIT FACILITIES 2015 2014

December 31, Maturity Total

Facilities Draws1 Available Total

Facilities (millions of Canadian dollars) Liquids Pipelines 2017 3,005 1,346 1,659 305 Total committed credit facilities2 3,005 1,346 1,659 305 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 2 On August 18, 2014, long-term private debt was issued for $352 million related to Southern Lights project financing. The

proceeds were utilized to repay the construction credit facilities on a dollar-for-dollar basis. Credit facilities carry a weighted average standby fee of 0.2% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and EIPLP has the option to extend the facilities, which are currently set to mature in 2017. Commercial paper and credit facility draws, net of short-term borrowings, of $1,346 million (2014 - $60 million) are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt.

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16. OTHER LONG-TERM LIABILITIES December 31, 2015 2014 (millions of Canadian dollars) Derivative liabilities (Note 20) 2,096 961 Asset retirement obligations (Note 17) 46 73 Regulatory liabilities (Note 5) 83 39 Other 67 34 2,292 1,107 17. ASSET RETIREMENT OBLIGATIONS The liability for the expected cash flows as recognized in the financial statements reflected discount rates ranging from 4.6% to 9.4% (2014 - 4.6% to 8.1%). A reconciliation of movements in EIPLP’s ARO is as follows: December 31, 2015 2014 (millions of Canadian dollars) Obligations at beginning of year 73 21 Liabilities incurred 2 50 Liabilities settled (31) - Change in estimate - - Accretion expense 2 2 Obligations at end of year 46 73 Presented as follows: Other long-term liabilities (Note 16) 46 73 46 73 In 2014, ARO in the amount of $50 million was recognized relating to the Canadian portion of the Line 3 Replacement Program, which is targeted to be completed in 2019, whereby EIPLP will replace the existing Line 3 pipeline in Canada. 18. PARTNERS’ INTERESTS As at December 31, 2015, the general partner interest included Class A units and the limited partners’ interests included Class A units, Class C units and Class D units. EIPLP also had one Class E unit and Special Interest Rights (SIR) outstanding at December 31, 2015. The limited partners have limited rights of ownership as provided for under the partnership agreement and, as discussed below, the right to participate in distributions. The general partner manages operations and participates in distributions. Earnings are allocated to the general partner and limited partners based on the HLBV method. All other amounts are allocated on a pro-rata basis between the partners based on their relative ownership percentages, inclusive of amounts arising as a result of the 2015 Transaction which were allocated to units in existence on the closing date of the 2015 Transaction. The limited partners’ capital accounts are limited to the balance of their capital account, and any allocation that draws the account to a deficit position is reallocated to the general partner.

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EXCHANGEABLE UNITS Class C Units 2015

December 31, Number of units Amount

(millions of Canadian dollars; number of units in millions) Balance at beginning of year - - Class C units issued1 443 15,697 Excess purchase price over historical carrying value acquired allocation

(Notes 2 and 6) - (9,611) Equity of former owners of Purchased Entities allocation2 - (1,997) Earnings allocation - 132 Class C unit distribution - (279) 443 3,942 Fair market value adjustment - 8,247 Balance at end of year 443 12,189 1 Issued as part of the 2015 Transaction (Notes 2 and 6). 2 Results from the retrospective adjustment to furnish comparative information related to the 2015 Transaction (Note 2). An unlimited number of Class C units are authorized. Class C units have direct voting rights and are entitled to non-cumulative distributions equivalent to distribution amounts on an ECT Preferred Unit and an ordinary trust unit of the Fund (Fund Unit) for the same distribution period. The holders of Class C units have an exchange right which allows for an exchange of the Class C units for Fund Units, ECT Preferred Units or common shares of ENF on a one-for-one basis at any time (Class C Exchange Right). Due to the Class C Exchange Right, the Class C units are classified as Mezzanine equity on the Consolidated Statements of Financial Position and recorded at their fair market value. Class D Units 2015

December 31, Number of units Amount

(millions of Canadian dollars, except number of units) Balance at beginning of year - - Class D units issued1 1,387,160 44 Class D unit distribution2 6,936 (1) 1,394,096 43 Fair market value adjustment - (5) Balance at end of year 1,394,096 38 1 Class D units issued on payment of TPDR distributions. 2 Class D units issued on payment of Class D unit distributions. Class D units are issued pursuant to the Temporary Performance Distribution Right (TPDR) distributions of the SIR. Class D units have direct voting rights and are entitled to non-cumulative distributions in the same amount as distributions paid in respect of a Class C unit. Distributions are paid-in-kind with newly issued Class D units equal to the amount of distribution declared payable, determined using the volume weighted average price of an ENF share for the five trading days prior to the distribution date. The holders of Class D units have an exchange right which allows for an exchange of the Class D units for Class C units at a deemed price per Class C unit benchmarked to the market price of an ENF share on the date of exchange (Class D Exchange Right). The Class D Exchange Right commences on the fourth anniversary of the year of issuance. Due to the Class D Exchange Right, the Class D units are classified as Mezzanine equity on the Consolidated Statements of Financial Position and recorded at their fair market value.

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Class E Unit 2015

December 31, Number of units Amount

(millions of Canadian dollars, except number of units) Balance at beginning of year - - Class E unit issued1 1 475 Balance at end of year 1 475 1 Issued as part of the 2015 Transaction (Notes 2 and 6). One Class E unit has been authorized and issued. The Class E unit does not receive distributions other than being entitled to receive a distribution amount approximately equal to the after-tax redemption amount of the Enbridge Employee Services Canada Inc. (EESCI) Series A Preferred Shares (Note 23), which will be paid in priority to all other distributions payable upon redemption of the EESCI Series A Preferred Shares. The Class E unit has no voting rights, except in limited circumstances. The Class E unit is redeemable for a redemption price equal to the Class E distribution. Due to the redemption feature, the Class E unit is classified as Mezzanine equity on the Consolidated Statements of Financial Position and recorded at its maximum redemption value. NON-EXCHANGEABLE UNITS Class A Units 2015 2014 2013 Number

of units Amount Number

of units Amount Number

of units Amount December 31, (millions of Canadian dollars; number of units in millions) Balance at beginning of year 245 5,049 187 3,289 187 3,289 Class A units issued1 112 3,874 58 1,760 - - Balance at end of year 357 8,923 245 5,049 187 3,289 1 In November 2015, 27 million Class A units were issued for gross proceeds of $874 million. In September 2015, 85 million

Class A units were issued for gross proceeds of $3,000 million as part of the 2015 Transaction (Notes 2 and 6). In November 2014, 58 million Class A units were issued for gross proceeds of $1,760 million as part of the 2014 Transaction (Notes 2 and 10).

An unlimited number of Class A units are authorized. Class A units have direct voting rights. Class A units’ distributions are equal to the distributable cash less the aggregate of all distributions properly payable on any other class of units and SIR. PREFERENCE RIGHTS Special Interest Rights 2015

December 31, Number of units Amount

(millions of Canadian dollars, except number of units) Balance at beginning of year - - Special interest rights issued1 1,000 2,565 Balance at end of year 1,000 2,565 1 Issued as part of the 2015 Transaction (Notes 2 and 6). An unlimited number of SIR are authorized. SIR have no direct voting rights, except in limited circumstances. The holders of SIR are entitled to receive Incentive Distribution Right (IDR) and TPDR distributions in priority to any distributions which are to be paid to holders of any other units, except the Class E unit. IDR distributions occur when the Fund Unit distribution rate exceeds $1.890 per unit and are paid in cash. TPDR distributions occur when the Fund Unit distribution rate exceeds $1.295 per unit and are paid in the form of Class D units.

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19. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE LOSS Changes in AOCI for the years ended December 31, 2015, 2014 and 2013, are as follows:

Cash Flow

Hedges

Cumulative Translation Adjustment Total

(millions of Canadian dollars) Balance at January 1, 2015 (81) 8 (73) Other comprehensive income/(loss) retained in AOCI (128) 80 (48) Other comprehensive (income)/loss reclassified to earnings

Interest rate contracts1 10 - 10 Commodity contracts2 (7) - (7) (125) 80 (45)

Tax impact Income tax on amounts retained in AOCI 34 - 34 Income tax on amounts reclassified to earnings - - -

34 - 34 Balance at December 31, 2015 (172) 88 (84)

Cash Flow

Hedges

Cumulative Translation Adjustment Total

(millions of Canadian dollars) Balance at January 1, 2014 39 3 42 Other comprehensive income/(loss) retained in AOCI (159) 5 (154) Other comprehensive (income)/loss reclassified to earnings

Interest rate contracts1 2 - 2 Commodity contracts2 (2) - (2) Foreign exchange contracts3 (1) - (1) (160) 5 (155)

Tax impact Income tax on amounts retained in AOCI 40 - 40 Income tax on amounts reclassified to earnings - - -

40 - 40 Balance at December 31, 2014 (81) 8 (73)

Cash Flow

Hedges

Cumulative Translation Adjustment Total

(millions of Canadian dollars) Balance at January 1, 2013 (57) (2) (59) Other comprehensive income retained in AOCI 82 5 87 Other comprehensive loss reclassified to earnings

Interest rate contracts1 45 - 45 Commodity contracts2 1 - 1 128 5 133

Tax impact Income tax on amounts retained in AOCI (20) - (20) Income tax on amounts reclassified to earnings (12) - (12)

(32) - (32) Balance at December 31, 2013 39 3 42 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Electricity sales revenues in the Consolidated Statements of Earnings. 3 Reported within Other income/(expense) in the Consolidated Statements of Earnings.

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20. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS MARKET PRICE RISK EIPLP’s earnings, cash flows and OCI are subject to movements in interest rates, foreign exchange rates and commodity prices (collectively, market price risk). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market price risks to which EIPLP is exposed and the risk management instruments used to mitigate them. EIPLP uses a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Interest Rate Risk EIPLP’s earnings, cash flows and OCI are exposed to short term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are used to hedge against the effect of future interest rate movements. EIPLP has implemented a program to significantly mitigate the volatility of short-term interest rates on interest expense through 2019 with the execution of floating to fixed rate interest rate swaps with an average swap rate of 1.4%. EIPLP’s earnings, cash flows and OCI are also exposed to variability in longer term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. EIPLP has implemented a program to significantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances through 2019 with the execution of floating to fixed rate interest rate swaps with an average swap rate of 3.1%. EIPLP’s portfolio mix of fixed and variable rate debt instruments is managed at the Fund Group level. Foreign Exchange Risk EIPLP generates certain revenues, incurs expenses and holds investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, EIPLP’s earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. EIPLP has implemented a policy whereby, at a minimum, it hedges a level of foreign currency denominated cash flow exposures over a five year forecast horizon. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. Commodity Price Risk EIPLP’s earnings, cash flows and OCI are exposed to changes in commodity prices as a result of its ownership interest in certain assets and investments. These commodities primarily consist of crude oil and power. EIPLP employs financial derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. EIPLP may use a combination of qualifying and non-qualifying derivative instruments to manage commodity price risk. TOTAL DERIVATIVE INSTRUMENTS The following table summarizes the Consolidated Statements of Financial Position location and carrying value of EIPLP’s derivative instruments. EIPLP did not have any outstanding fair value hedges as at December 31, 2015 or 2014. EIPLP generally has a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of its derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce EIPLP’s credit risk exposure on derivative asset positions outstanding with the counterparties in these particular circumstances. The following table also summarizes the maximum potential settlement amount in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position.

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December 31, 2015

Derivative Instruments

Used as Cash Flow Hedges

Non-Qualifying Derivative

Instruments

Total Gross Derivative

Instruments as Presented

Amounts Available for

Offset

Total Net Derivative

Instruments (millions of Canadian dollars) Accounts receivable and other (Note 8) Foreign exchange contracts 1 1 2 - 2 Interest rate contracts 1 - 1 (1) - Commodity contracts 7 9 16 (5) 11 9 10 191 (6) 13 Deferred amounts and other assets (Note 12) Foreign exchange contracts 2 - 2 - 2 Commodity contracts 6 1 7 (6) 1 8 1 9 (6) 3 Accounts payable and other (Note 14) Foreign exchange contracts - (430) (430) - (430) Interest rate contracts (86) - (86) 1 (85) Commodity contracts - (29) (29) 5 (24) (86) (459) (545)2 6 (539) Other long-term liabilities (Note 16) Foreign exchange contracts - (1,860) (1,860) - (1,860) Interest rate contracts (77) - (77) - (77) Commodity contracts - (159) (159) 6 (153) (77) (2,019) (2,096) 6 (2,090) Total net derivative asset/(liability) Foreign exchange contracts 3 (2,289) (2,286) - (2,286) Interest rate contracts (162) - (162) - (162) Commodity contracts 13 (178) (165) - (165) (146) (2,467) (2,613) - (2,613)

December 31, 2014

Derivative Instruments

Used as Cash Flow Hedges

Non-Qualifying Derivative

Instruments

Total Gross Derivative

Instruments as Presented

Amounts Available for

Offset

Total Net Derivative

Instruments (millions of Canadian dollars) Accounts receivable and other (Note 8) Foreign exchange contracts - 2 2 (2) - Commodity contracts - 16 16 - 16 - 18 18 (2) 16 Deferred amounts and other assets (Note 12) Foreign exchange contracts 1 - 1 - 1 Commodity contracts 14 2 16 (14) 2 15 2 17 (14) 3 Accounts payable and other (Note 14) Foreign exchange contracts - (101) (101) 2 (99) Interest rate contracts (51) - (51) - (51) Commodity contracts - (12) (12) - (12) (51) (113) (164)2 2 (162) Other long-term liabilities (Note 16) Foreign exchange contracts - (703) (703) - (703) Interest rate contracts (82) - (82) - (82) Commodity contracts - (176) (176) 14 (162) (82) (879) (961) 14 (947) Total net derivative asset/(liability) Foreign exchange contracts 1 (802) (801) - (801) Interest rate contracts (133) - (133) - (133) Commodity contracts 14 (170) (156) - (156) (118) (972) (1,090) - (1,090) 1 Reported within Accounts receivable and other (2015 - $7 million; 2014 - $1 million) and Accounts receivable from affiliates

(2015 - $12 million; 2014 - $17 million) on the Consolidated Statements of Financial Position. 2 Reported within Accounts payable and other (2015 - $87 million; 2014 - $10 million) and Accounts payable to affiliates (2015 -

$458 million; 2014 - $154 million) on the Consolidated Statements of Financial Position.

1

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The following table summarizes the maturity and notional principal or quantity outstanding related to EIPLP’s derivative instruments. December 31, 2015 2016 2017 2018 2019 2020 Thereafter Interest rate contracts - short-term borrowings (millions of Canadian

dollars) 1,507 1,498 511 36 25 216 Interest rate contracts - long-term debt (millions of Canadian dollars) 780 560 610 200 - - Foreign exchange contracts - United States dollar forwards - sell

(millions of United States dollars) 1,568 1,564 2,008 1,807 1,424 787 Foreign exchange contracts - United States dollar forwards -

purchase (millions of United States dollars) 119 2 2 2 2 - Commodity contracts - power (megawatt hours (MWH)) 40 40 30 31 35 (35) December 31, 2014 2015 2016 2017 2018 2019 Thereafter Interest rate contracts - short-term borrowings (millions of Canadian

dollars) 107 178 114 151 28 242 Interest rate contracts - long-term debt (millions of Canadian dollars) 730 420 210 - - - Foreign exchange contracts - United States dollar forwards - sell

(millions of United States dollars) 1,415 1,312 1,564 2,008 1,807 2,211 Foreign exchange contracts - United States dollar forwards -

purchase (millions of United States dollars) 94 2 2 2 2 2 Foreign exchange contracts - Euro forwards - purchase

(millions of Euros) 1 - - - - - Commodity contracts - power (MWH) 22 40 40 31 31 1 The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income The following table presents the effect of cash flow hedges on EIPLP’s consolidated earnings and consolidated comprehensive income, before the effect of income taxes. Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Amount of unrealized gains/(loss) recognized in OCI

Cash flow hedges Foreign exchange contracts 2 1 1 Interest rate contracts (38) (174) 32 Commodity contracts 6 11 3 (30) (162) 36 Amount of gains/(loss) reclassified from AOCI to earnings (effective portion) Foreign exchange contracts1 - (1) - Interest rate contracts2 9 3 45 Commodity contracts3 (7) (2) 1 2 - 46 Amount of loss reclassified from AOCI to earnings (ineffective portion and

amount excluded from effectiveness testing) Interest rate contracts2 - (1) (2)

- (1) (2) 1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of

Earnings. 2 Reported as an increase/(decrease) within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Electricity sales revenues and Other income/(expense) in the Consolidated Statements of Earnings. EIPLP estimates that $2 million of AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the interest rates, foreign exchange rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which EIPLP is hedging exposures to the variability of cash flows is 48 months at December 31, 2015.

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Non-Qualifying Derivatives The following table presents the unrealized gains and losses associated with changes in the fair value of EIPLP’s non-qualifying derivatives. Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Foreign exchange contracts1 (1,487) (522) (353) Commodity contracts2 (8) 3 (91) Total unrealized derivative fair value loss (1,495) (519) (444) 1 Reported within Transportation and other services revenues (2015 - $1,382 million loss; 2014 - $495 million loss; 2013 - $352

million loss) and Other income/(expense) (2015 - $105 million loss; 2014 - $27 million loss; 2013 - $1 million loss) in the Consolidated Statements of Earnings.

2 Reported within Transportation and other services revenues (2015 - $9 million loss; 2014 - $13 million gain; 2013 - $5 million loss) and Operating and administrative expense (2015 - $1 million gain; 2014 - $10 million loss; 2013 - $86 million loss) in the Consolidated Statements of Earnings.

LIQUIDITY RISK Liquidity risk is the risk EIPLP will not be able to meet its financial obligations, including commitments (Note 24) and guarantees (Note 25), as they become due. In order to manage this risk, EIPLP forecasts cash requirements over the near and long term to determine whether sufficient funds will be available when required. EIPLP generates cash from operations, commercial paper issuances and credit facility draws, through the periodic issuance of public term debt and issuance of units to its partners. Additionally, to ensure ongoing liquidity and to mitigate the risk of market disruption, EIPLP maintains a level of committed bank credit facilities. In addition, to ensure adequate liquidity, EIPLP actively manages its bank funding sources to optimize pricing and other terms. Additional liquidity, if necessary, is expected to be available through intercompany transactions with Enbridge or other related entities. CREDIT RISK Entering into derivative financial instruments may result in exposure to credit risk. Credit risk arises from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, EIPLP enters into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, frequent assessment of counterparty credit ratings and netting arrangements. EIPLP had group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2015 2014 (millions of Canadian dollars) Canadian financial institutions 1 1 European financial institutions 1 - Other1 15 20 17 21 1 Other is comprised of primarily Enbridge and its affiliates. Derivative assets are adjusted for non-performance risk of EIPLP’s counterparties using their credit default swap spread rates, and are reflected in the fair value. For derivative liabilities, EIPLP’s non-performance risk is considered in the valuation. Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits, contractual requirements, assessment of credit ratings and netting arrangements. Generally, EIPLP classifies and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

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FAIR VALUE MEASUREMENTS EIPLP’s financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. EIPLP also discloses the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects EIPLP’s best estimates of market value based on generally accepted valuation techniques or models and are supported by observable market prices and rates. When such values are not available, EIPLP uses discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value. FAIR VALUE OF FINANCIAL INSTRUMENTS EIPLP categorizes its financial instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. EIPLP does not have any financial instruments valued using Level 1 inputs. Level 2 Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward contracts and interest rate swaps for which observable inputs can be obtained. EIPLP has also categorized the fair value of its investment in affiliated company and long-term debt as Level 2. The fair value is based on quoted market prices for instruments of similar yield, credit risk and tenor. Level 3 Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives' fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. EIPLP has developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs include long-dated derivative power contracts, basis swaps, commodity swaps, power and energy swaps, options and long-dated commodity derivative contracts. EIPLP uses the most observable inputs available to estimate the fair value of its derivatives. When possible, EIPLP estimates the fair value of its derivatives based on quoted market prices. If quoted market prices are not available, EIPLP uses estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, EIPLP uses standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, EIPLP uses observable market prices (interest, foreign exchange and commodity) and volatility as primary inputs to these valuation techniques. Finally, EIPLP considers its own credit default swap spread as well as the credit default swap spreads associated with its counterparties in its estimation of fair value.

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Fair Value of Derivatives EIPLP has categorized its derivative assets and liabilities measured at fair value as follows:

December 31, 2015 Level 1 Level 2 Level 3

Total Gross Derivative

Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts - 2 - 2 Interest rate contracts - 1 - 1 Commodity contracts - 8 8 16 - 11 8 19 Long-term derivative assets Foreign exchange contracts - 2 - 2 Commodity contracts - - 7 7 - 2 7 9 Financial liabilities Current derivative liabilities Foreign exchange contracts - (430) - (430) Interest rate contracts - (86) - (86) Commodity contracts - - (29) (29) - (516) (29) (545) Long-term derivative liabilities Foreign exchange contracts - (1,860) - (1,860) Interest rate contracts - (77) - (77) Commodity contracts - - (159) (159) - (1,937) (159) (2,096) Total net financial asset/(liability) Foreign exchange contracts - (2,286) - (2,286) Interest rate contracts - (162) - (162) Commodity contracts - 8 (173) (165) - (2,440) (173) (2,613)

December 31, 2014 Level 1 Level 2 Level 3

Total Gross Derivative

Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts - 2 - 2 Commodity contracts - 16 - 16 - 18 - 18 Long-term derivative assets Foreign exchange contracts - 1 - 1 Commodity contracts - 1 15 16 - 2 15 17 Financial liabilities Current derivative liabilities Foreign exchange contracts - (101) - (101) Interest rate contracts - (51) - (51) Commodity contracts - - (12) (12) - (152) (12) (164) Long-term derivative liabilities Foreign exchange contracts - (703) - (703) Interest rate contracts - (82) - (82) Commodity contracts - - (176) (176) - (785) (176) (961) Total net financial asset/(liability) Foreign exchange contracts - (801) - (801) Interest rate contracts - (133) - (133) Commodity contracts - 17 (173) (156) - (917) (173) (1,090)

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The significant unobservable inputs used in fair value measurement of Level 3 derivative instruments were as follows:

December 31, 2015 Fair Value Unobservable

Input Minimum

Price Maximum

Price

Weighted Average

Price

Unit of

Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial1

Power (173) Forward power price 30.00 73.76 53.44 $/MWH 1 Financial forward commodity contracts are valued using a market approach valuation technique. If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of EIPLP’s Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices and, for option contracts, price volatility. Changes in forward commodity prices could result in significantly different fair values for EIPLP’s Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally speaking, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility. Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Year ended December 31, 2015 2014 (millions of Canadian dollars) Level 3 net derivative liability at beginning of year (173) (172) Total gains/(loss), unrealized Included in earnings1 (1) (11) Included in OCI (1) 10 Settlements 2 - Level 3 net derivative liability at end of year (173) (173) 1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in

the Consolidated Statements of Earnings. EIPLP’s policy is to recognize transfers as of the last day of the reporting period. There were no transfers between levels as at December 31, 2015 or 2014. Fair Value of Other Financial Instruments At December 31, 2015, EIPLP’s long-term debt had a carrying value of $5,605 million (2014 - $3,693 million) and a fair value of $5,833 million (2014 - $4,216 million). At December 31, 2015, EPI, a subsidiary of EIPLP, had an investment of $514 million (2014 - nil) in non-voting, redeemable Series A Preferred Shares in EESCI (Note 23). EIPLP has classified this investment in affiliated company as available-for-sale debt security and carries it at fair value, with changes in fair value recorded in OCI. As at December 31, 2015, the fair value of this investment approximates its cost and redemption value. EIPLP holds Class A Units of Southern Lights Holdings, L.L.C., which is an indirect wholly-owned subsidiary of Enbridge, providing defined, scheduled and fixed distributions that represent the equity cash flows derived from the core rate base of Southern Lights US until June 30, 2040. At December 31, 2015, EIPLP’s investment had a carrying value of $844 million (2014 - $719 million) included in Long-term receivable from affiliate and Accounts receivable from affiliates on the Consolidated Statements of Financial Position and a fair value of $820 million (2014 - $719 million).

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21. INCOME TAXES INCOME TAX RATE RECONCILIATION Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Earnings before income taxes 121 626 579 Federal statutory income tax rate 15% 15% 15% Expected federal taxes at statutory rate 18 94 87 Increase/(decrease) resulting from: Provincial and state income taxes (76) (55) (3) Foreign and other statutory rate differentials 23 19 12 Effects of rate-regulated accounting1 (29) (72) (1) Part VI.1 tax, net of federal Part I deduction2 54 47 24 Deductible dividends (2) (10) (9) Unremitted foreign subsidiary earnings 4 - - Earnings in non-taxable entities (38) (24) (20) Non-taxable portion of capital gains and losses (12) - - Other (1) (4) (6) Income taxes (recovery)/expense on earnings (59) (5) 84 Effective income tax rate (48.8%) (0.8%) 14.5% 1 The amount in 2015 and 2013 included the federal component of the tax effect of the write-off of regulatory receivables. 2 In 2013, this tax was presented net of a $10 million federal tax recovery related to changes in tax law enacted during the year. COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Earnings before income taxes Canada 4 563 517 United States 117 63 62 121 626 579 Current income taxes (recovery)/expense Canada 154 13 (70) United States 1 23 23 155 36 (47) Deferred income taxes (recovery)/expense Canada (253) (56) 130 United States 39 15 1 (214) (41) 131 Income taxes (recovery)/expense on earnings (59) (5) 84

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COMPONENTS OF DEFERRED INCOME TAXES Deferred tax assets and liabilities are recognized for the future tax consequences of differences between carrying amounts of assets and liabilities and their respective tax bases. Major components of deferred income tax assets and liabilities are as follows: December 31, 2015 2014 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (1,352) (1,063) Investments (275) (212) Regulatory assets (272) (220) Deferred revenue (103) (119) Other (5) - Total deferred income tax liabilities (2,007) (1,614) Deferred income tax assets Financial instruments 688 258 Asset retirement obligations 29 18 Loss carryforwards 273 103 Other 13 15 Total deferred income tax assets 1,003 394 Net deferred income tax liabilities (1,004) (1,220) Presented as follows:

Accounts receivable and other (Note 8) 40 22 Deferred income taxes 246 242 Total deferred income tax assets 286 264 Accounts payable and other (15) - Deferred income taxes (1,275) (1,484) Total deferred income tax liabilities (1,290) (1,484) Net deferred income tax liabilities (1,004) (1,220)

As at December 31, 2015, EIPLP recognized the benefit of unused tax loss carry forwards of $1,014 million (2014 - $404 million) in Canada which expire in 2031 to 2035. EIPLP and its subsidiaries are subject to taxation in Canada and the United States. The material jurisdictions in which EIPLP is subject to potential examinations are within Canada (Federal, Alberta, Ontario and Quebec) and the United States (Federal, Illinois, Iowa, Minnesota, North Dakota and Wisconsin). EIPLP is open to examination by certain Canadian tax authorities for the 2009 to 2015 tax years and by certain United States tax authorities for the 2014 and 2015 tax years. EIPLP is currently under examination for income tax matters in Canada for the 2011 and 2012 taxation years. UNRECOGNIZED TAX BENEFITS EIPLP has no unrecognized tax benefits related to uncertain tax positions as at December 31, 2015 and no accrued interest or penalties thereon.

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22. CHANGES IN OPERATING ASSETS AND LIABILITIES Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Accounts receivable and other (63) 159 (90) Accounts receivable from affiliates (6) (15) 42 Deferred amounts and other assets 111 (169) (195) Accounts payable and other (378) (196) 119 Accounts payable to affiliates 379 83 (25) Interest payable 8 (1) 8 Other long-term liabilities (3) 191 (517) 48 52 (658) 23. RELATED PARTY TRANSACTIONS All related party transactions are entered into in the normal course of business and, unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. Affiliates refer to Enbridge and companies that are either directly or indirectly owned by Enbridge. The acquisition of the Purchased Entities and equity investment in Alliance Pipeline US were accounted for as transactions among entities under common control. See Notes 6 and 10, respectively, for additional disclosure. GENERAL PARTNER Enbridge Income Partners GP Inc. (EIPGP), a subsidiary of Enbridge, is the general partner of EIPLP and has a 0.01% interest in the Class A units of EIPLP. As at December 31, 2015, Enbridge holds a 51% direct interest in EIPGP. Per EIPLP’s partnership agreement, EIPGP has the right to manage, control and operate the businesses of EIPLP. EIPGP delegates the execution of certain of its powers to Enbridge Management Services Inc. (EMSI or the Manager), a wholly-owned subsidiary of Enbridge, who administers EIPLP. INTERCORPORATE SERVICES On August 2, 2015 all Canadian employees of EPI and EPAI were transferred to an affiliated company which assumed all employment related obligations, commitments and liabilities. The related net pension and other postemployment benefit liabilities, as well as the related unamortized losses recorded in AOCI, were not included in the retrospective consolidated financial statements as EIPLP has elected to recognize required contributions for the period as net pension costs without reflecting related plan benefit obligations and plan assets. Pension related costs of $45 million for the year ended December 31, 2015 (2014 - $48 million; 2013 - $51 million) were recorded in Operating and administrative expense on the Consolidated Statements of Earnings. As at December 31, 2015, EIPLP and its subsidiaries do not have any employees and receives services from affiliates for managing and operating the business. These services, which are charged at cost in accordance with service agreements or which reflect normal commercial trade terms, totalled $234 million for the year ended December 31, 2015 (2014 - $90 million; 2013 - $82 million). EIPLP provides certain operational services to affiliates. These services, which are charged at cost in accordance with service agreements or which reflect normal commercial trade terms, totalled $166 million for the year ended December 31, 2015 (2014 - $214 million; 2013 - $177 million). LIQUIDS PIPELINES EIPLP has contracts with shippers who are also affiliates of EIPLP through common ownership interests of Enbridge. Revenues from affiliates, which reflect normal commercial trade terms, totalled $78 million for the year ended December 31, 2015 (2014 - $51 million; 2013 - $71 million).

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GAS PIPELINES Alliance Pipeline has contracts with shippers that are also affiliates of EIPLP through common ownership interests of Enbridge. EIPLP’s share of Alliance Pipeline’s revenues from affiliates for the year ended December 31, 2015 was $59 million (2014 - $50 million; 2013 - $50 million). LONG-TERM RECEIVABLE FROM AFFILIATE Long-term receivable from affiliate includes the carrying value of Class A Units of Southern Lights Holdings, L.L.C., which is an indirect wholly-owned subsidiary of Enbridge. As at December 31, 2015, $826 million (2014 - $707 million) is included in Long-term receivable from affiliate and $18 million (2014 - $12 million) is included in Accounts receivable from affiliates. Interest income of $61 million for the year ended December 31, 2015 (2014 - $5 million; 2013 - nil), has been recorded within Other income - affiliates on the Consolidated Statements of Earnings. INVESTMENT IN AFFILIATED COMPANY As at December 31, 2015, EIPLP had an investment of $514 million in 500,000 non-voting, redeemable Series A Preferred Shares of EESCI. These Preferred Shares entitle EIPLP to receive annual dividends through 2021. EESCI has the option to redeem the outstanding Preferred Shares at any time. EIPLP is also entitled to require redemption of these Preferred Shares at any time. Dividend income of $14 million was recognized in Other income - affiliates for the year ended December 31, 2015 (2014 - nil; 2013 - nil). During the year ended December 31, 2015, a subsidiary of Enbridge exercised its option to redeem the $160 million in 160,000 non-voting, redeemable preference shares that were held as an investment by EPAI, a subsidiary of EIPLP. The investment was acquired in 2014 and entitled EPAI to receive a minimum cumulative quarterly dividend equal to 106.25% of the cost of funds incurred by EPAI to finance its acquisition of these preference shares. Dividend income of $4 million was recognized in Other income - affiliates for the year ended December 31, 2015 (2014 - $12 million; 2013 - nil). During the year ended December 31, 2014, Enbridge Energy Distribution Inc. (EEDI) exercised its option to redeem the $2,690 million in 2.69 million non-voting, redeemable, retractable preference shares of EEDI that were held as an investment by EPI, a subsidiary of EIPLP. The investment was acquired in 2013 and entitled EPI to receive a cumulative quarterly dividend equal to 106.25% of the cost of funds incurred by EPI to finance its acquisition of these preference shares. INTERCORPORATE LOANS AND BALANCES Loans to Affiliates The following loans to affiliates are evidenced by formal loan agreements. Interest rates for short-term loans are based on the applicable short-term LIBOR for the United States dollar loans and Canadian Depository Offering Rate for the Canadian dollar loans. 2015 2014

December 31,

Maturity

Weighted Average Interest

Rate

Amount

Weighted Average Interest

Rate

Amount (millions of Canadian dollars) Affiliate Current 6.0% 3 - - Affiliate - - - 12.0% 3 Enbridge - - - 7.9% 325

3 328 Current portion of loans to affiliates (3) (3) - 325

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Loans from Affiliates The following loans from affiliates are evidenced by formal loan agreements: 2015 2014

December 31,

Maturity

Weighted Average Interest

Rate

Amount

Weighted Average Interest

Rate

Amount (millions of Canadian dollars) Enbridge 2020-2064 4.6% 4,191 - - Enbridge 2025 4.0% 124 - - Affiliate Current 1.9% 47 2.4% 216 Affiliate Current 4.3% 48 4.3% 31 Affiliate 2020 7.1% 100 7.1% 100 Affiliate 2045 4.0% 734 - - Affiliate 2045 4.0% 652 - - Enbridge - - - 3.3% 3,463 Enbridge - - - 4.8% 3,307 Enbridge - - - 7.2% 160 Affiliate - - - 1.6% 634 Affiliate - - - 1.5% 487 Affiliate - - - 3.5% 229 5,896 8,627 Current portion of loans from affiliates (95) (8,367)

5,801 260 Loans from affiliates’ maturities for the year ending December 31, 2016 are $95 million, nil for each of the years ending December 31, 2017 through 2019 and $600 million for the year ending December 31, 2020. These loans are subordinate to senior, unsecured debt. The affiliate loan interest obligations for the year ending December 31, 2016 are $273 million, $260 million for each of the years ending December 31, 2017 through 2019 and $240 million for the year ending December 31, 2020. As at December 31, 2015, EIPLP had a net hedge payable balance of $2,501 million (2014 - $1,023 million net payable) to affiliates in respect of derivative instruments that the affiliates entered into on EIPLP’s behalf. These amounts are recorded in Accounts receivable from affiliates, Deferred amounts and other assets, Accounts payable to affiliates and Other long-term liabilities on the Consolidated Statements of Financial Position.

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24. COMMITMENTS AND CONTINGENCIES At December 31, 2015, EIPLP had commitments as detailed below:

Total

Less than

1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Purchase of services, pipe and

other materials, including transportation 1,952 1,456 354 50 19 8 65

Capital and operating leases 18 5 4 2 1 - 6 Maintenance agreements 420 46 46 31 25 19 253 Land lease commitments 131 6 7 7 7 7 97 Total 2,521 1,513 411 90 52 34 421 OTHER LITIGATION EIPLP and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, the Manager believes that the resolution of such actions and proceedings will not have a material impact on EIPLP’s consolidated financial position or results of operations. 25. GUARANTEES In the normal course of conducting business, EIPLP enters into agreements that involve providing certain guarantees for affiliates. EIPLP has guaranteed the Fund’s credit facilities of $1,500 million which mature in 2018 and medium-term and floating rate notes which mature from 2016 to 2044. As at December 31, 2015, no amounts were drawn on the credit facilities and there was $2,405 million outstanding on the notes. No amounts have been accrued for these guarantees as it is not currently likely EIPLP will have to pay any amounts with respect to these guarantees.